Operators in Argentina are reversing the Neuquén basin's gas production decline by targeting low-permeability, tight gas reservoirs. Shale gas resources will fuel production growth toward the end of the decade, but tight gas resources are the focus of short-term drilling. With widely variable well results, a statistical approach is required to spread the productivity risk among a large number of wells. Our Latin America upstream experts examine six tight gas formations in the Neuquén basin to determine the way forward to improve well economics.
While conventional production in the Neuquén basin has been steadily declining, tight gas production has almost tripled since 2014. Reaching 565 million cubic feet per day (mmcfd) in Q1 2016, tight gas accounts for one quarter of the basin’s gas output.
The shift is being driven by pricing incentives and lower costs versus shale gas wells. Drilling has focused on the Grupo Cuyo and Mulichinco tight sand formations.
Well performance, however, has been extremely variable. The median tight gas well in the Nequén basin has an IP90 rate of 2 mmcfd, but well results show great dispersion — the top-quartile wells perform five times higher than the bottom quartile.
Variable well economics require a statistical approach
Our study of six tight gas formations reveals that the highest EUR potential comes from horizontal wells in the Mulichinco formation, at 5 billion cubic feet (bcf) for the top-quartile wells. Punta Rosada vertical wells have similar potential with a vertical design. Both are profitable at or below the US$7.50/mmbtu incentivised gas price. Additional well cost reductions are needed for type wells in all formations to be economic at the US$5.20/mmbtu average gas price without incentive.
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This wide variability in results suggests that a statistical development approach remains necessary to spread the productivity risk among a number of wells via large, multi-well development programs.
Higher EURs more achievable than lower costs
Capital efficiency ratios ('000 US$ per boe/d and US$ per boe) in Neuquén's tight sands are in line with unconventional wells in the Karnes Trough and Edwards Condensate sub-plays of the Eagle Ford in southern Texas, as we discuss in our recent US Lower 48 research report .
Our analysis shows that the tight gas wells with the highest costs also have the highest EURs and IP rates, achieving lower breakeven prices than cheaper wells. Enhancing EURs through more expensive wells (horizontal sections, increased frac stages) across all formations presents a more plausible path to improving tight gas well economics than the significant cost reductions otherwise required to improve economics at current EURs.