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Unravelling the US Shale
OIES PAPER: WPM 69
Co-Founder PetroNerds &
OIES Research Associate
The contents of this paper are the authors’ sole responsibility. They do not
necessarily represent the views of the Oxford Institute for Energy Studies or any of
Copyright © 2016
Oxford Institute for Energy Studies
(Registered Charity, No. 286084)
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ISBN 978-1-78467-072-6 i November 2016 – Unravelling the US Shale Productivity Gains Contents
2. The productivity gains
The Powder River basin
The Eagle Ford
3. The factors behind productivity gains
Addition by subtraction
Productivity gains not a fluke
How lower costs have enabled productivity gains
Doing more with less
Taking advantage of low costs
Techniques and technological advances – reducing frack waste
Figures Figure 1: EUR growth in the Permian, Williston (Bakken), and Powder River basins (2014–16)..........1 Figure 2: Aggregated oil decline curve for horizontal Permian, Williston, and Powder River wells (2011–16)
Figure 3: Oil production in four plays (2013–16)
Figure 4: Well additions in four plays, horizontal and vertical (2013–16)
Figure 5: Permian basin type curves (2011–16)
Figure 6: Permian basin vertical and horizontal well oil production (2000–16)
Figure 7: Williston basin type curves (2011–16)
Figure 8: Powder River basin type curves (2011–16)
Figure 9: Eagle Ford reservoir type curves (2011–16)
Figure 10: EOG Resources, Eagle Ford reservoir type curve (2011–16)
Figure 11: Performance increase of selected top producers by reservoir (2014–16)
ii November 2016 – Unravelling the US Shale Productivity Gains
1. Introduction Several US shale and tight oil plays have exhibited robust well productivity gains1 over the past two years, even as oil prices enter a third consecutive year under $60 per barrel. The Permian, Williston (Bakken), and Powder River basins have produced the most significant gains over this period.
Estimated ultimate recovery factors (EUR)2 are one measurement of well productivity. Initial 12-month oil EURs (the cumulative amount of oil a well will produce in its first 12 months) for the three plays, in aggregate, have grown by 41 per cent from 2014 to 2016, while 60-month EURs have grown by 22 per cent over that same period (see Figure 1). This begets the question, how can such strides be made in a low oil price environment in which operators and service companies alike are cutting costs, laying off employees, and reducing activity levels?
Figure 1: EUR growth in the Permian, Williston (Bakken), and Powder River basins (2014–16) 25% 20% 15% 10% 5%
Notes: Year-on-year 12 and 60-month EUR growth rates for oil producing wells brought online in a given year in the Permain, Williston, and Powder River basins (individual well data has been combined across the three plays).
Source: DrillingInfo Data, PetroNerds Calculations and Estimates Figure 2 illustrates the decline curve, or average well performance, for all active horizontal wells in the Permian, Williston, and Powder River basins combined, brought online in specified years. The horizontal axis shows the age of these wells in months, and the vertical axis shows the average daily oil production of these wells. Each line represents the performance of wells brought online in a given year. The orange line represents the performance of wells brought online in 2016, the light dark blue represents wells brought online in 2015, and so on. Notice how the curve shifts upward in the past three years indicating improvement in well productivity. 3 Note that productivity gains are most apparent in the first two years of a well’s life. After the two-year mark, performance tends to standardize across all well years (the tails overlap).
‘Well productivity’ refers to the output of a well over a given period of time. Increased output over a given period is considered to represent productivity gains.
‘Estimated Ultimate Recovery’ refers to the total amount of oil and/or gas a well is expected to produce over a given time period.
When the curves shift upward year-on-year, this indicates that wells are producing more oil at a given age than the previous year’s wells produced at that same age. As long as the curve remains above or in line with the previous year’s curve, EUR factors grow as well.
November 2016 – Unravelling the US Shale Productivity Gains Figure 2: Aggregated oil decline curve for horizontal Permian, Williston, and Powder River wells (2011–16) b/d
Source: PetroNerds, DrillingInfo Data Many US shale and tight oil producers have stated that they have become both leaner and more efficient, while also achieving technological and scientific gains that will persist when the oil market improves and, inevitably, service costs rise. However, leading oilfield service providers have stated publicly that oil producers have made few, if any, lasting technological strides or efficiency gains.
Rather, they contend that producers have simply benefited from cuts in service costs (such as cost savings in drilling and completion) and that any gains or improvements will not persist when costs rise. Schlumberger stated the following in their Second Quarter, July 2016 earnings call (Seeking
The operators have reacted to this crisis by initiating a massive reduction in oilfield activity and by sending unsustainable pricing shock throughout the entire oil industry supply chain.
In addition, there is currently also a widespread high-grading of activity taking place in the industry aimed at maximizing short-term production and cash flow.
Adding up all of this, the current cost per barrel for the oil producers now appears to be significantly lower than what was the case seven quarters ago. However, this should not be confused with a permanent improvement in the underlying industry performance as there has been little to no fundamental change in technology, quality or efficiency, no major step change in industry collaboration and no general transformation of the industry business model.
November 2016 – Unravelling the US Shale Productivity Gains While Schlumberger’s tone has moderated in their most recent earnings call, their words in July serve as a harsh rebuttal to conflicting statements from a number of operators. Oasis Petroleum discussed several Bakken-related developments that are leading to increased oil recovery – specifically
completion design changes – in their Second Quarter, August 2016, earnings call (Seeking Alpha):
Equally important to cycle times are job design and implementation. Last quarter, we spoke about many of the completion designs that we are testing this year. These tests fall into two camps: higher proppant loadings and proppant placement efficiency. 4 For high-proppant loads, we have completed multiple 10 million pound and 20 million pound fracs in Indian Hills and Wild Basin. For proppant placement, we have completed several 50-stage slickwater jobs and have also tested both diverters and precision proppant placement techniques... it’s simply too early to draw definitive conclusions. However…we believe these designs and techniques have the potential to further enhance both EURs and returns for Oasis.
In their Second Quarter, August 2015 call, EOG discussed the customization of well completion
designs and the resulting effects on decline rates, and the uplift in well productivity (Seeking Alpha):
… we continue to drill our laterals in better rock … we are taking a lot of time and effort, picking out the best quality rock in each one of these plays and keeping the lateral in that longer … we now are doing a much better job with these high density fracs and better distributing the frac along the lateral, connecting up more of that good rock.5 And it [is] certainly lowering our decline rates over time and that makes it easier to grow production…No two wells are exactly the same. We always customize the completion job based on the geology…. But, we are seeing a tremendous uplift in the productivity of the wells.
Source: All earnings call quotes via SeekingAlpha.com
Notable here is that EOG mentions the major step changes taking place in completions design. These changes include deeper assessment of rock quality, the importance of keeping the well lateral in higher quality rock or reservoir, and also optimizing the placement fracks along the lateral, as opposed to the common practice of placing frack stages at pre-defined, standard intervals. These and many of the other completion changes will be explained throughout the course of this paper.
This paper seeks to assess the level of well productivity changes and well production improvements in the US shale and tight oil space since the collapse of oil prices in 2014. This paper also seeks to analyse the nature of these productivity changes through an assessment of the role of cost cuts, efficiency gains, and technology advances on the performance of recently developed shale and tight oil wells. This assessment is performed through the analysis of individual well data and research into company behaviour through earning calls, press releases, and meetings with key shale companies.
‘Higher proppant loading’ refers to the addition of large volumes of proppant (such as sand) as part of the hydraulic fracturing process. Proppant volumes vary by basin (and even within basins) and by operator over the course of the oil price downturn.
However, the amount of sand loadings per lateral foot of wellbore has continued to steadily rise across all basins. ‘Proppant placement efficiency’ refers to the more precise placement of proppant, typically sand, downhole. This also refers to the treatment of the well through the completion process and improved placement of the fractures during completion to better connect the rock and increase production.
The term ‘high density fracs’ here is a specific reference to EOG’s statement regarding their fracturing treatment method – a method that primarily utilizes more sand and more frack stages. ‘Frac distribution’ refers to the actual distribution of the fracture stages along the wellbore and the placement of those perforation clusters.
November 2016 – Unravelling the US Shale Productivity Gains
2. The productivity gains Several US shale and tight oil plays have benefited from significant oil well productivity gains since the downturn began in 2014. The focus of this paper is on productivity gains in the Permian, Williston, and Powder River basins, although several other basins and plays, including the Anadarko basin and the Eagle Ford’s oil window, have also seen productivity increases.
Figure 3 and Figure 4 show oil production and new horizontal and vertical well additions, for wells that remain active, in the Permian, Williston, and Powder River basins, and the Eagle Ford reservoir.
Permian basin production has grown throughout the downturn, even with a sharply declining rate of well additions. (Vertical well production has declined considerably in the Permian, but strong growth in horizontal well production has more than offset these declines.) Eagle Ford production has declined markedly since the spring of 2015 given reduced activity levels and the varying product windows: oil, volatile oil, condensate, and gas production in the reservoir. Williston basin production has also continued to decline, as many producers have allocated available capital to other plays. Powder River basin production has declined, but it appears to be holding steady at current levels due to increased completion activity undertaken by larger producers.
Figure 3: Oil production in four plays (2013–16) 2013 2014 2015 2016 (as of August) 2,098 1,891 1,648 1,496 1,368 1,347
1,156 1,090 1,036
5,897 3,865 3,586 3,143 1,650
Source: DrillingInfo Data, PetroNerds November 2016 – Unravelling the US Shale Productivity Gains The Permian The Permian basin, which spans from across West Texas into south-eastern New Mexico, has been a prominent conventional US oil play for nearly a century. But in the past several years, shale oil production techniques – such as horizontal drilling and hydraulic fracturing – have been applied at scale to numerous reservoirs in the Permian basin, morphing it into a hybrid conventional/unconventional tight oil play and reversing the basin’s downward production trajectory.
Remarkably, Permian basin oil production has grown by a third (500,000 b/d) since the start of 2014.
The Permian basin is the ‘hottest’ play at the moment. In 2016 there have been a large number of acreage sales, acquisitions, and discovery announcements while acreage prices have skyrocketed, all in the midst of sub-$60 oil prices.
Growth has, in large part, been spurred by the application of unconventional drilling technologies (which are becoming more conventional by the day) in reservoirs that had previously been treated as conventional formations – such as the Bone Spring, the Trend Area, and the Wolfcamp reservoirs.
Figure 5 shows annual type curves for horizontal wells added since 2011. Note the sharp upward shift of the curves that began in 2014 – the start of the oil price collapse – as the broad application of unconventional oil production techniques became widespread. Initial production (IP) rates rose from less than 300 b/d for 2013 wells to over 500 b/d for 2016 wells, while tails for the first 36 months of a well’s life are holding above the tails of wells from 2013 and earlier.