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Qarnain Foda

Qarnain Foda

Qarnain Foda is the co-founder of the energy analytics blog enernomics.org. With a background in oil field services, he specializes in economic analysis of the…

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Argentina’s Shale Industry Makes Progress, But No Boom Yet

Argentina is advancing in its mission to become the largest shale oil and gas producer outside of North America. But well economics still challenge the industry, despite heavy price supports from the government.

While production from conventional wells in the Neuquén basin has steadily declined, tight gas production has almost tripled over the past two years with an average of 18 new wells drilled per month in the basin, reaching 565 mmcfd (16Mm3/d) during the first quarter of 2016.

As drilling and completion costs vary across the basin, estimated ultimate recovery (EUR) may play a greater role in well economics than reducing costs, where only outstanding wells break even at the incentivised US$7.50 /MMBTU according to the latest Wood Mackenzie analysis.

After years of decline in natural gas production, Argentina has been rejuvenating the local industry by offering higher prices on output from new developments. The program was designed to encourage exploration and increase production by setting a fixed price on natural gas output from new projects at $7.50 /MMBTU, up from the current average of $5.20 /MMBTU.

(Click to enlarge)

Source: Woodmac

Operators are targeting five tight gas formations in the Neuquén basin: Mulichinco horizontal (Hz) and vertical (Vt), Punta Rosada, Lajas, Precuyo, and Los Molles. The median 90-day initial production rate (IP90) of a tight gas well in the Neuquén basin is about 2 mmcdf (56 km3/d); however, recent analysis indicates a great degree of variability in IP90 and EUR across all tight gas formations. Related: Oil Prices In Freefall As Fundamentals Worsen

The below whisker diagram indicates the distribution of the IP90 rates by formation where the extremes of the box are the lower (Q1) and upper (Q3) quartiles. The median is marked by the vertical line inside the box, the mean by the white dot inside the box, the two lines outside the box extend to the highest and lowest observations, and the outliers are the dots above or below the lines.

Source: Woodmac

(Click to enlarge)

Although Multichinco horizontal wells have the highest range of IP90 rates, Punta Rosada wells demonstrate lower variability around a higher median, while the remaining formations achieve significantly lower median IP90 rates around 1.4 – 1.8 mmcfd (40-50 km3/d). This high degree of variability indicates the requirement for a statistical development approach to spread productivity risk amongst a large number of wells as discussed by Horacio Cuenca, Director of Latin America Upstream Research for Wood Mackenzie.

The estimated cost of horizontal wells is about US$8.5 million where longer laterals and more fracture stages significantly enhance production but come at an increased well cost. Vertical wells with fewer fracturing stages are estimated to cost between US$4.5 million and US$6 million. Total well costs of each tight gas formation have been estimated, accounting for drilling, completions and tie in to existing infrastructure.

(Click to enlarge)

Source: Woodmac

The higher median and lower variability in production from Punta Rosada formation come with a higher average well cost of US$12.8 million due to the depth of the formation and higher number of fracturing stages required. Related: Oil Slammed After EIA Reports Significant Crude Build

Although the drilling and completion costs play a major role in the economics of a well, the relationship between the cost of these wells and the productivity achieved is equally critical. The Wood Mackenzie study shows that the highest cost wells also demonstrate the highest EUR and rates of initial production. Using type-well EUR and current well cost estimates, Mulichinco wells and Punta Rosada wells, the two most expensive formations in the basin on average, are the only wells profitable at or below the government incentivised natural gas price of US$7.50/mmbtu.

The takeaway here is this: While regulated gas price incentives may be temporary, well costs would need to drop by as much as 70 percent to be profitable at the non-incentivised price of US$5.20/mmbtu. It is more viable that operators aim to achieve higher EURs to reduce breakeven prices rather than reducing costs.

By Qarnain Foda for Oilprice.com

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