All the DUCs in a Row: Natural Gas Production in U.S.

AuthorMugabe, Douglas
PositionDrilled but uncompleted wells

    Understanding the determinants of natural gas supply is important because of its significance for the U.S. power sector (Peters and Hertel, 2017; Stephens, 2018) and U.S. economic activity in general (Arora and Lieskovsky, 2014; Melick, 2014; Weber, 2012; Joskow, 2013). (1) Previous academic literature relied on drilling rig activity (the count of actively drilling rigs) as the primary determinant of oil and gas production because of the simplicity, availability, and global applicability of drilling rig count as an indicator (Apergis, Ewing and Payne, 2016; Melek, 2015). The oil and gas industry also has been relying on the rig count as a measure of oil and gas production activity. (2) However, as Figure 1 illustrates, natural gas production in the U.S. increased even though drilling activity has declined in recent years (EIA, 2019a).

    With the growth in the use of hydraulic fracturing and horizontal drilling technologies, market analysts, researchers and government agencies have noted the increase in the inventory of drilled but uncompleted wells (DUCs) in the U.S. (Hegarty, 2017; EIA, 2013; EIA, 2019b; Dunning, 2016; Srinivasan, Krishnamurthy and Kaufman, 2019; IHS, 2016; Piotrowski, 2016). However, little or no systematic information is available on the growth of DUC inventory and the implications for natural gas production. This paper examines the determinants of DUC inventories and the impacts of drilling rig activity and well completion on natural gas output in the U.S.

    Technological developments in unconventional oil and gas (UOG) production have transformed the U.S. gas industry. According to the U.S. EIA, domestic production of gas from the UOG industry grew by more than 100% from 2000 to 2010. Data from the EIA (2016a) also indicate that the daily production of U.S. dry shale increased from 2.5 in 2002 to 43 billion cubic feet in 2016, with most of the new production coming from the Northern Appalachian basin (Marcellus and Utica shale units). Substantial gains in productivity continue through advances such as super pads (which can include up to 20 wells), extended horizontal laterals (reaching up to 20 thousand feet (3)) and improved drilling and fracturing technologies. The share of horizontally drilled wells increased from 3% in 2008 to 12% in 2017 (EIA, 2018). As a result, although the number of drilling rigs fell since 2014, natural gas production continued to grow (Figure 1) (EIA, 2019a).

    In general, UOG production involves two stages. The first stage involves drilling, casing the well with multiple strings of steel pipe, and cementing the pipe. In the second stage (completion), the steel casing is perforated, and the well is stimulated via hydraulic fracturing to initiate gas flow from fractured formations. Completion, which can be significantly more expensive and time consuming than the first stage activities, can be delayed indefinitely. However, interrupting the flow from a producing well can be prohibitively costly in terms of foregone income (Kleinberg et al., 2018). Hence, production timing decisions take the form of drilling and completion decisions corresponding to stages one and two, respectively (Mason and Roberts, 2018). Wells drilled (stage one), but not hydraulically fractured or completed are labeled as drilled but uncompleted wells (DUCs).

    Figure 2 shows that the aggregate number of DUCs has increased since 2007 across all regions. From November 2016 to the end of 2017, the number of DUCs rose 37.4% to 7,493 (DI, 2016). EIA's (2019a) drilling productivity report shows more than 8,700 DUCs as of November 2018. Growth in DUCs varies by region, with the largest increase observed in the Permian Basin. The reasons for the delays in well completion, and consequent growth in the DUC numbers, may include: shortage of hydraulic fracturing equipment and teams, contractual lease obligations that require active well development in stage one, pipeline capacity bottlenecks, and operators' timing decisions to take advantage of favorable prices (EIA, 2019b; Kleinberg et al., 2018).

    One implication of the increase in DUCs is that aggregate natural gas production depends less on drilling rig activity and more on well completion rates. As a result of growth in unconventional production, and associated two-stage production technology use, drilling rig counts no longer directly correspond to the number of producing wells. Hence, the number of completed wells may be increasingly important for modeling natural gas production. Though the drilling rig count remains an important factor in natural gas production, supply growth is achieved with fewer drilling rigs given improvements in drilling technology and despite the backlog of DUCs (EIA, 2019a).

    Importantly, for the production to grow, the productivity of new wells must offset declines in productivity of legacy wells (Boyce and Nostbakken, 2011). Therefore, this paper considers both the number of producing wells and the number of newly completed wells as drivers of natural gas output. The objectives of this study are threefold. First, we examine the role of well completion rates in explaining natural gas production. Second, we examine the determinants of DUC numbers, which represent the gap between drilled and completed wells. Third, we identify the factors that influence the length of time that operators take to complete the unconventional wells.

    The literature on the determinants of natural gas production is limited. Iledare (1995) uses a supply model for natural gas reserve additions in West Virginia to study the responsiveness of drilling effort and gross reserve additions to changes in the expected wellhead price, taxes, resource depletion and reserve life index. He concludes that drilling activity shifts across geological formations in response to varying geologic conditions and economic incentives. Boyce and Nostbakken (2011) show a positive correlation between output prices and drilled wells, considering a significant decrease in the cost of drilling. Chen and Linn (2017) examine the effects of oil and gas futures prices on drilling activity in the U.S. and the rest of the world. They show that drilling activities respond to futures prices more than spot prices. This is consistent with the industry practice of hedging gas production. Gulen et al. (2013) also document the sensitivity of drilling new wells to changes in natural gas prices. Similar results with a positive association between oil rig activity and crude oil prices have been documented by Ringlund, Rosendahl and Skjerpen (2008), Apergis et al. (2016), Anderson, Kellogg, and Salant (2018) and Khalifa, Caporin and Hammoudeh (2017).

    Mason and Roberts (2018) examine the sensitivity of well level natural gas production in Wyoming to geologic and economic factors. They show that geologic factors affect intra-well production variation (well productivity) while prices affect inter-well production changes (number of producing wells) via producer drilling decisions. They conclude that after a well has started producing, prices have limited effect on well-level production. Instead, geologic and engineering factors determine well productivity. However, prices have a significant effect on aggregate supply due to the elasticity of producers' drilling decisions. The authors show that at lower prices, only the most productive wells are drilled, while higher prices enable drilling of less productive wells. They also observe that the elasticity of drilling decisions in Wyoming increased following the growth in the use of horizontal drilling and hydraulic fracturing technologies. Ikonnikova and Gulen (2015) also examine the effect of prices on drilling activities in Barnett, Haynesville, and Fayetteville shale units. They show that at lower prices, producers in some locations may find it more profitable to rely on low-cost infill (4) wells to minimize capital costs as opposed to drilling relatively more productive but costlier wells in new locations.

    None of the previous studies examine growth in the DUC numbers and the relationships between gas production, drilling rig activity and well completion across shale regions in the U.S. We disentangle these variables, which allows us to present a more nuanced account of production activities given the recent growth in the number of drilled but uncompleted wells. Our results document greater explanatory power of the number of producing wells relative to the count of active rigs for modeling natural gas production. (5) We also show that changes in oil and gas futures prices and drilling rig activity affect DUC numbers and the length of time that operators take to complete individual wells.

  2. DATA

    Unconventional shale gas production makes up more than 50% of all-natural gas produced in the U.S and its contribution continues to increase with most of the production coming from seven major shale regions (EIA, 2017). This study is based on the data from Anadarko, Appalachia (Marcellus and Utica), Bakken, Eagle Ford, Haynesville, Niobrara and Permian regions.

    We use monthly regional data from January 2007 to July 2018 to examine cumulative natural gas production and DUC counts, and daily well level data from 2000 to 2018 to estimate hazard ratios. (6) The data summary is presented in Table 1. Rig count and natural gas production (7) (million cubic feet - mmcf) data are obtained from the EIA. Well completion data obtained from DrillingInfo (now Enverus) include a monthly cumulative number of producing wells. Rig count data (disregarding the differences in rig requirements across regions due to geological characteristics) are provided by Baker Hughes.

    Rig activity in this study reflects only the number of actively (8) drilling rigs. Figure 2 presents data trends for drilling rig counts, DUCs, and gas production. Since 2007, natural gas production has been increasing significantly in most regions, except in Niobrara and Haynesville...

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