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US Light Tight Oil (LTO) – Completion Technology v Geology

Ciaran Nolan, September 2016

Introduction

US LTO production has grown ten-fold from it’s infancy in 2008 to a peak of 4.5 million barrels per day in 2015 (Figure 1). Since then, production has dropped to 4.0 million barrels per day1 as a consequence of lower oil prices, equivalent to 4% of global liquid production. During the last three years, producers and oilfield service companies have reduced costs via multi-pad drilling, more efficient rigs, improved well/completion designs and optimised gathering systems. Longer horizontals with up to 50 stage fraccs combined with improved proppant types, hybrid fluid systems are targeting the best play sweet spots10. This has resulted in a significant increase in short term productivities. Lower costs and higher volumes have combined to reduce break even oil prices, with some LTO producers quoting break-even oil prices as low as $302.

This paper summaries work by the author on the Bakken / Three Forks Play and quantifies and differentiates the impact of completion technology versus geology on single well economics and break-even oil prices.

Bakken / Three Forks Play

The Bakken and Three Forks Play in the Williston Basin, is the second largest producing LTO play in the world, at 0.95 million barrels per day (Figures 1 and 2) and accounts for just under 25% of US LTO production1, with over 98% of production in North Dakota. The Bakken has had a similar exponential growth in production to the total US LTO, and the percentage of gas produced has doubled from 11% in 2008 to 22% in 2016 (Figure 2). North Dakota releases it production data via the North Dakota Industrial Commission (NDIC)3. NDIC monthly production data has been compiled and kindly supplied by Enno Peters4. The dataset has recently been extended and updated to include production data from previously confidential wells. Oil and gas production data from 2008 onwards was investigated, comprising 10367 wells.

Bakken / Three Forks: Impact of Completion Technology on Production

Many LTO producers and analysts have highlighted the improvements in productivities via Initial Production rates (IP), average 90 day rates and production. Decline curves such as the Arps model6

are used to extrapolate well production and derive Estimated Ultimate Recoveries (EUR) per well. The duration of production on which EURs are estimated is rarely stated, but can be based on an economic cut-off or a fixed time period. 20 years was used in this study. Significant uncertainties exist in terminal decline rates and beta factors6.

Analysis of the NDIC data in this study and others4 has yielded average production curves by year (for 2008 to 2015) for oil and gas, Figures 3-6. Figure 3 illustrates the increase in 0-18 month oil production from 2008 to 2015, and Figure 4 is for gas. Note how the increase for gas is much larger and lasts for longer. For oil, note the proximity (+/- 5 bopd) of the tail-end part of the curves (after24 months). Detailed inspection of the oil curves for the 0-200 bopd range (Figure 5) reveal a cross-over point at 18 months, with 2012-2015 rates higher in the 0-18 month period but then declining below the 2008-2011 curves after 18 months. Also worth noting is the increase in 2008 rates after 70 months due to refraccing. Around 13% of 2008 wells were refracced5. A big unknown in economic modelling is the amount of well intervention that will be required after 5-10 years of production and if intervention is economically justifiable. A reasonable fit was established between hyperbolic decline curves (based on the Arps formula) and the actual data for 0-18 months, but the tail-end fits were poor. A hybrid set of curves (Figure 6) was established using actual production data and power law functions for future tail-end production, as the power law provided a better fit to actual data in the tail-end period. These result in terminal annual decline rates of 5-8%, which are arguably on the optimistic side6.

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The table in Figure 6 summarises the production for the 2008-2015 curves as well as 20 year income based on $60/bbl oil and $2.80/mcf for gas. The average 90 day oil + gas production for the Bakken has increased 57% from 2008 to 2015. When this is broken out into oil v gas, gas only production has increased 169% whereas oil only production has increased 44%. When extrapolated to a life of field/well duration of 20 years, oil + gas production has increased by 12%, gas only by 55%, oil only by 5% and revenue by 10%. The average 20 year oil only production for 2008 – 2015 is relatively constant at 350-370 mbo. Improved completions have in effect brought forward oil production but overall oil only EURs are unchanged. Oil plus gas EURs have however increased 12%.

Bakken / Three Forks: Impact of Completion Technology on Break-Even Oil Prices

Average break-even oil price estimates for individual US LTO plays vary widely and an accurate comparison of the break-even cost estimates by various producers and analysts is often a case of comparing ‘apples and oranges’. These differences are the result of varying assumptions in costs, forward commodity prices and decline curves. Producers have a significant number of drilled uncompleted wells (DUCs). These are currently being completed at an average incremental cost of c.$3.5 million. Most Bakken producers have responded to lower oil prices by only completing DUCs within their core areas. Drilling and completing new wells at a total cost of $6-7 million is still ongoing but at a much reduced level. EURs have increased however production has started to decline.

In early 2016 Wood Mackenzie published an average break-even oil prices for Pre-FID projects including the Bakken7. The average break-even price for the Bakken was $63 Brent ($61 WTI). Bloomberg Intelligence estimate is $41 WTI8, NDIC quote a statewide break-even price of $26 WTI9 – see Figures 7-9. Some break-even estimates only assume the future CAPEX involved in DUC completion (i.e. $3.5million) and not the total historical and future costs of drilling and completion the well ($6-7 million).

In this study, the 2008 – 2015 decline curves were modelled to determine NPV, IRR and break-even oil prices. The various cost, tax, royalty and depreciation assumptions used in the models are summarised in Figure 10. No capital costs were included for future well intervention, re-fraccing or abandonment. A total drilling and completion cost of $7 million was used. All assumptions are the same from year to year, the only variable being the decline curve itself. The 57% increase in 90 day oil + gas production between 2008 and 2015 type wells equates to a 10% increase in revenue, and a lowering of the average break-even oil price for from $68 to $60 WTI (Figure 11). The $60 estimate for 2015 is in line with Wood Mackenzie’s average Bakken break-even price of $63 Brent (c. $61 WTI)7.

Large increases in near term (0-18 month) oil and gas production from 2008 to 2015 translate into relatively modest reduction in life of field (20 year) break-even oil price. Lower drilling, completion and operating costs have however resulted in a significant reduction in life of field break-even oil prices10.

Bakken / Three Forks: Impact of Geology/Area on Break-Even Oil Prices

The 10376 study wells were ranked by 12 month oil only production and split into deciles that defined nine typed curves P10-P90 – Figures 12-15. Unlike the 2008-2015 curves, the P10-P90 curves reveal significant variations in tail-end production (Figure 14 and 15) which is mainly related to geology/area. The curves were modelled to determine NPV, IRR and break-even oil prices. The various cost, tax, royalty and depreciation assumptions used in the models are summarised in Figures 16. The break-even oil price varies from $43 for a P10 well to $93 for a P90 well, the P50 type well estimate is $61 WTI – Figure 17.

The break-even oil prices were plotted up against 12 month oil production and these points sit on a power law relationship (Figure 18) - WTI break-even oil price = one year oil production*565.4^0.507 (R2 = 0.993). The twelve month production data from the 10376 wells were imported into IHS

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Kingdom and gridded. The power law equation was applied to generate a break-even map (Figure 19). Core Bakken areas with break-evens of $61 WTI or less are illustrated in yellow to pink. Also displayed on the map are wells that started producing in 2016, note the close correspondence between location of the wells and the parts of the Bakken with lower break-even oil prices, Bakken core areas.

Conclusions - Completion Technology v Geology

Early stage LTO production (0-18 months) is controlled by geology and completion technology. Year on year increases in early stage production is mainly related to advances in completion technology (average geology stays the same) i.e. longer horizontals, > number of stages, reduced spacing between stages, improved proppant technology. Later stage, tail-end, production (>18 months) is mainly related to geology. Average yearly oil only decline curves converge to +/-5 BOPD. Decline curves generated in this study reveal a cross-over point at 18 months, with 2012-2015 rates higher in the 0-18 month period but then declining below the 2008-2011 curves after 18 months. The average 20 year oil only production, predicted from decline curves in this study, for 2008 – 2015 is relatively constant at 350-370 mbo. Large increases in near term oil and gas production from 2008 to 2015 translate into a relatively modest (from $68 to $60 WTI) reduction in the life of field break-even oil prices. Improved completions have brought forward oil production but overall oil only EURs are unchanged.

Some of the larger Bakken producers quote 2016 oil + gas EUR targets of >800 mboe. A large inventory of DUCs enables companies to carefully select completions only within core Bakken areas (P50-P10). This comes at the expense of overall production. The ability to complete a DUC in a P50 area versus a P10 area reduces the break-even oil price from $61 to $43 WTI, i.e. a much bigger impact than improving completion technology. Ninety percent of wells that started producing in 2016 are located in the core Bakken areas (P50-P10).

Analysis of Bakken decline curves in this study demonstrates geology and hence location is the main controlling factor in LTO well economics.

Acknowledgements

Thanks to Enno Peters for supplying the recently updated and formatted NDIC data (public domain). Thanks to Will Foiles at Bloomberg Intelligence and Enno Peters for lots and lots of feedback.

References

1. EIA - http://www.eia.gov/analysis/studies/usshalegas/ 2. EOG – Q4 2015 Results (page 15) http://investors.eogresources.com/Presentations-and-

Events?item=22 3. North Dakota Industrial Commission (NDIC) https://www.dmr.nd.gov/oilgas/ 4. Enno Peters - http://shaleprofile.com/ 5. Enno Peters – pers. comm. 6. Rystad Energy - http://www.rystadenergy.com/NewsEvents/Newsletters/UsArchive/shale-

newsletter-august-2016 7. Woodmac - Pre-FID oil projects: global breakeven analysis, Jan. 2016

http://www.woodmac.com/analysis/PreFID-oil-projects-global-breakeven-analysis 8. Bloomberg Intelligence Estimates of Breakeven Prices in Shale Plays, April 2016 - pers. comm. 9. NDIC Director’s Cut, August 2016, https://www.dmr.nd.gov/oilgas/directorscut/directorscut-

2016-08-12.pdf 10. Trends in U.S. Oil and Natural Gas Upstream Costs EIA, March 2016 -

https://www.eia.gov/analysis/studies/drilling/pdf/upstream.pdf

Figure 1 – United States - Light Tight Oil Production

C. J Nolan Sept. 2016

C. J Nolan Sept. 2016

Increase in percentage of production that is gas from 11%

to 22% from 2008 to 2016

Figure 2 – North Dakota Bakken / Three Forks Oil and Gas Production

C. J Nolan Sept. 2016

Figure 3 – North Dakota Bakken / Three ForksMean Yearly Oil Only Production

0-18 month production is a combination of reservoir and fracture dominated flow. Increases in mean rates

year to year mainly related to advances in completion technology (longer horizontals, > number of stages, reduced spacing between stages, improved

proppant technology)

After 18 months production is mainly reservoir dominated flow. Decline curves converge.

Geology is the main controlling factor. Average geology hasn’t changed year to year.

C. J Nolan Sept. 2016

Figure 4 – North Dakota Bakken / Three ForksMean Yearly Gas Only Production

Increases in 0-12 month gas rates are much larger and for longer.

C. J Nolan Sept. 2016

Figure 5 – North Dakota Bakken / Three ForksMean Yearly Oil Only Production

At around 18 months of oil production there is a crossover point, with 2012-2015 rates higher

in the 0-18 month period but then declining below the 2008-2011 curves afterwards.

Increase in 2008 rates after 70 months due to refraccing. Around 13% of 2008

wells were refracced6.

C. J Nolan Sept. 2016

Figure 6 – North Dakota Bakken / Three ForksMean Oil Production by Year

Mean BAKKEN BE = $63 (Brent)

Figure 7 – Wood Mackenzie Global Comparison of BE Oil Prices

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Figure 8 - Bloomberg Intelligence – US LTO BE Oil Prices – April 2016

Mean BakkenBreak-even = $41 (WTI)

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Figure 9 – NDIC BE Oil Prices by County – August 2016

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Figure 10 – North Dakota Bakken / Three ForksSingle Well Economic Model by Year - Assumptions

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*Forward looking economics over 20 year period. All costs, taxes, royalties are the same. See Figure 10 for inputs.

Figure 11 – North Dakota Bakken / Three ForksEstimated Mean Break-Even Oil Price by Year*

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Figure 12 – North Dakota Bakken / Three Forks12 Month Oil Only Production*

*10367 wells ranked by 12 month oil only production and split into deciles. Incomplete first month production estimated using mean correction for days produced (x1.6

C. J Nolan Sept. 2016

• Wells with 1 year full production that started producing Jan. 2008

• 10367 wells.• Hot colours = higher production• Incomplete first month production estimated

using mean correction for days produced (x1.6)

Figure 13 – North Dakota Bakken / Three Forks12 Month Oil Only Production Heat Map

C. J Nolan Sept. 2016

10376 wells ranked by 12 month production and split into deciles. Nine type curves defined; P10-P90

Figure 14 – North Dakota Bakken / Three ForksP10 – P90 Oil Only Production Decline Curves - Actual

C. J Nolan Sept. 2016

Power functions fitted to P10-P90 decline curves. Variation in IP rate and position of

tail related to geology

Figure 15 – North Dakota Bakken / Three ForksP10 – P90 Oil Only Production Decline Curves - Modelled

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Figure 16 – North Dakota Bakken / Three ForksSingle Well P10 – P90 Economic Model Assumptions

C. J Nolan Sept. 2016

*Forward looking economics over 20 year period. All costs, taxes, royalties are the same. See Figure 16 for inputs and cost assumptions.

Figure 17 – North Dakota Bakken / Three ForksP10 – P90 Break-Even WTI Oil Prices*

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Figure 18 – North Dakota Bakken / Three ForksBreak Even WTI Oil Price v Year One Oil Only Production*

*Power law: WTI BE oil price = one year oil production*565.4^-0.507

Figure 19 – North Dakota Bakken / Three ForksBreak-Even WTI Oil Price Map

• Coloured areas breaking even at $65 or less (Bakken core areas)• Wells that started producing in 2016 displayed• Close correspondence between 2016 wells and Bakken core areas

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