Article: Validation of Shale Production Modeling & Forecasting Per Magnus Nysveen, Head of Analysis, and Leslie Wei, Analyst
Article:Mapping Global Shale Potential Roman Boros, Senior Analyst
RYSTAD ENERGY PRODUCT HIGHLIGHTS
Rystad Energy offers a wide product range of North American shale products (NASAnalysis).
NASCube: Database that provides US and Canada shale gas and tight oil plays data for 380+ companies and 138 shale plays and sub-plays. Data derives from Rystad Energy’s global and complete upstream database UCube, with additional information regarding acreage and well data.
NASWellData: Collection of official well data, covering over 200,000 horizontal and fracked vertical wells, with complete US shale coverage, and including well attributes, monthly production rates at well level, reported and calculated initial production rates, well configuration parameters as well as short-term activity and production forecasts.
NASReport: Up-to-date play coverage incorporating prospectivity maps, company-specific data, acreage and reserves, production forecasts of plays up to 2025 as well as infrastructure and economics of plays.
NASMaps: Geological, company acreage and well location maps. Maps are available as pdf-layers and GIS files with embedded information for import to GIS software.
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The average well performance across the US shale plays has improved significantly over time, specifically during 2015 with low oil prices. All key metrics for drilling, completion and well cost have improved across the main shale oil plays this year. Nonetheless, one important question to raise is how much more can these efficiencies increase in the coming years, as companies drill up their core areas i.e. sweet spots.
All main shale oil plays increased drilling efficiency in 2015 and on average, one rig currently drills up to 16 horizontal wells per year with a total measured depth of 15,000 ft. In the Niobrara shale play one rig drills up to 27 of these type of wells, the largest among the main shale oil plays. Wells in Niobrara are drilled with an average lateral length of 7,000 ft and 93% pad drilling. A key reason of improved drilling efficiency is the deferral of older rigs, leaving mostly the newly build and more efficient rigs still drilling in the shale plays. Towards 2016, pad drilling in Niobrara is expected to continue at current 2015 levels, similar to what is expected for Bakken. Further drilling efficiency can be expected in the Permian Basin.
All main shale oil plays have increased the average lateral length of the wells in 2015. Niobrara has been the play with the largest increase in lateral length per well during this year, mainly due to longer laterals drilled by Anadarko, Bill Barret and Noble Energy. These longer lateral wells have required larger amounts of proppant, which gives an indication of bigger stages, hence more reservoir contact that ultimately results in higher oil recovery. This case is more prominent in Permian Delaware wells, which have had a slight increase in lateral length but a significant increase in proppant use.
Permian Delaware wells now recover just 85 thousand bbl less of oil EUR than Bakken wells, 22% above average in US shale plays. Further improvements in well performance can be expected among all shale plays except Eagle Ford, which has shown a similar 90-day initial production rate since 2012 at nearly 600 boe/d and marginal increases in Oil EUR, even though proppant use in this play has increased consistently every year. Such trends in the Eagle Ford play affect the drilling and completion (D&C) well cost per EUR, which over the last four years has decreased the least in comparison to other main shale oil plays, as shown in Figure 4.
Eagle Ford wells have marginally decreased the well cost per EUR in 2015, only 3% yearly and still above 10 $/bbl. The Permian Midland shale play, on the other hand, has decreased the yearly well cost per EUR by 15% in 2015 and 61% since 2011. A decreasing well cost per EUR indicates that companies are able to recover more volumes for every dollar spent. During 2015, most operators improved in this metric mainly due to drilling only their best acreage i.e. high grading, but the size of such areas or sweet spots is limited. At the current well spacing, companies will drill up their core areas in about eight years, by assuming a drilling level similar to that one in 2014.