Oil and gas companies’ dependent on production and cash flow from already drilled but uncompleted wells will benefit from capital efficiency gains in 2016, but conversion of those wells won’t be able to measure up to new drilling activities, according to new analysis from global research firm IHS.
Since the collapse of crude oil and natural gas prices pushed U.S. drilling activities to historic low levels in 2016, oil and gas drillers like Arkansas’ Fayetteville Shale leader Southwestern Energy and rival Chesapeake Energy kept the lights on with cash flow by stacking up inventories of so-called drilled but uncompleted wells, or DUCs. IHS defines DUCs as a location in which the well has reached target depth, but has not finished the completion process such as perforation and hydraulic fracturing, or fracking.
In its May 10 report, analysis from IHS’s Houston-based energy research group indicates there is an estimated 380,000 barrels per day of production to be derived from the 2,750 net remaining through September 2017, which is just 16% of the estimated U.S. oil wedge production volume of 2.45 million barrels per day.
For natural gas drillers like Southwestern and other Fayetteville Shale players like Southwestern, Australia-based BHP Billiton and ExxonMobil’s XTO Energy, IHS estimates that production will peak at 3.5 billion cubic feet (BCF) per day in October 2017, accounting for only 19% of wedge volumes of 18.58 BCF per day.
“While the overall production implications for U.S. supply are relatively small, on a company performance level, these DUC wells are critical to the operators that have them in their 2016 inventory because they will deliver production and significant capital efficiencies,” said Stephen Beck, senior director of energy research for the North America Onshore Service at IHS Energy. “At IHS, we estimate that total spending to convert all existing DUCS to production is approximately $11.5 billion, which represents an estimated 40% savings of the capital it would require to drill and complete a new well. In this low-price environment, that is a significant savings for operators who have DUCs in their inventories.”
‘DRILL AND HOLD’ STRATEGY
Some of the operators with the largest remaining inventories of DUC wells include EOG Resources, Anadarko and Chesapeake Energy, IHS said. Operators such as Anadarko and EOG are two of the few known operators who employed a “drill and hold” strategy and intentionally accumulated DUCS to shape growth when oil and gas prices increased, IHS said. The companies continued to drill wells with rigs that were under contract rather than terminate the contracts and defer the completions of these wells.
IHS said delays in bringing these wells into production vary significantly by play, impacting supply forecasts. However, because of the DUC analysis, which is the only commercially available well-level and field-level assessment of these DUCs in major U.S. plays, IHS has been able to identify consistent patterns for conversion, based on well and play analysis.
“When assessing the conversion strategies and production impacts from these DUCs, we at IHS found that in all major U.S. plays, with the exception of those in Appalachia, there is a clear and consistent pattern of first-in, first-out (FIFO) development for these plays,” Beck said. “Our IHS research found that this pattern of development is due to ordinary field-operating procedures inherent to pad drilling. Standard practices in pad drilling generate lags between when these wells are drilled and when they are completed. Typically, this conversion lag-time averages about 120 days, but can extend to as long as nine months. This variability in the lag times is why DUC conversion estimates can impact production and supply forecasts materially.”
To optimize their pad drilling efficiencies and minimize risk, oil and gas operators typically drill all the wells on one pad then move to the second and third pads, if present, and do the same until all wells are drilled, Beck said. The operators will then proceed with the completion process.
“Drilling all the wells at once enables operators to negotiate better rates with service companies, who in turn, get the benefit of larger projects, but this leads to a batch-processing nature. This batch processing results in the formation of these DUC wells, but it also drives a natural delay as it relates to the completions of these DUCs, which also follow in batches,” Beck said.
The IHS analysis said the speed of conversion of these DUCs in any particular play is largely driven by the geology of the play and the operators in the play, some of whom have tremendous history, experience and understanding of the geology, which allows greater efficiencies.
ASSESSING THE SUPPLY FORECAST
According to IHS, the plays with a natural inventory of DUCs include the Fayetteville, Eagle Ford, Bakken, Permian horizontal plays (Bone Spring, Midland Wolfcamp and Delaware Wolfcamp), Niobrara horizontals (Wattenburg and Niobrara fracture), Marcellus, Utica, Arkoma Woodford and Mississippian. Of these, IHS said, 70% of current DUCs exist in predominantly oil plays, while 30% are found in gas plays.
“What our IHS Energy analysis illustrates is that it is imperative to have a strong understanding of field operations in order to assess the impact of these DUCs and achieve a truly accurate assessment of the supply forecast for a specific play or for North America as a whole,” Beck said. “This is important because, in this price environment, technology continues to forge ahead to drive greater efficiencies, so we are seeing drilling times diminish further and they will continue to do so moving forward. On a positive note, in terms of operators, the survivors of this downturn are likely to be better off than before because they will be eliminating unnecessary costs and inefficiencies, creating stronger organizations.”
And although Southwestern is not mentioned in the IHS’s report, the Fayetteville Shale producer’s new CEO Bill Way recently unveiled his new strategic plans to position the company for future growth by slowly bringing already drilled wells into production until natural gas prices rebound above the $3 per MMbtu break even mark.
Under Way’s helm, Southwestern only invested a measly $120 million in its exploration and production business in the first quarter with more than half of that tally ($62 million) expended just to covered capitalized interest and expenses. That left only $58 million to place 12 wells in production in the first quarter, and plans to put 20 to 30 wells to sales during 2016.
In 2016, Southwestern’s gross operated gas production in the Fayetteville Shale was approximately 1.6 Bcf per day as the natural gas producer completed 3 wells and placed 9 wells into production. The Houston-based natural gas giant, which has slashed its capital budget by 80% to $140 million from $565 million a year ago, plans to place an additional six wells into production in the Arkansas shale play in the second quarter.
Beck said the delayed conversion of DUCs to producing wells in the last few years explains the “resiliency in U.S. production, and in part, accounts for its recent recognition as the world’s new ‘swing producer.’
“The U.S. energy system doesn’t turn on a dime,” Beck said, “but it does turn faster than an oil tanker. It can respond to changes in price in less than a year, which is not the case for other resources elsewhere.”