A version of this story appears in the October 2017 edition of Oil and Gas Investor. Subscribe to the magazine here.

Like aging members of an English-rocker tribute band, E&Ps are now singing the praises of “My Generation” completions.

Essentially, E&Ps are employing new terms to describe the evolutionary nature of enhanced or optimized completion practices.

However defined, those efforts have given rise to larger IPs (primarily reflecting longer laterals) and allowed E&Ps to expand EURs. When it comes to My Generation completions, E&Ps envision a Lake Wobegon oil patch where all type curves are better than average.

There have been three major iterations in horizontal well evolution over the last half-decade. These include greater proppant loading after 2012 (coupled with the transition to slickwater fracks), extended lateral length after 2014 and precise lateral landing after 2015.

Improvements in geosteering now enable best-in-class E&Ps to land wellbores in the best 10 to 20 feet of reservoir rock even as lateral length increases.

At the end of the day, rock quality remains the main factor determining well productivity. Meanwhile, closer stage spacing and more perforation clusters per stage allow laterals to access reservoir potential by enhancing near-well bore hydrocarbon recovery, hence greater IPs.

Leading-edge E&Ps are now working on a fourth iteration by addressing spacing issues, whether placing stages closer together with more perforation clusters between stages on individual laterals, spacing between adjoining laterals in the same formation or, at the very leading edge, in adjoining formations above and below the parent well (stack and stagger).

So, what gives? Some of it is science; much of it is economic. The main challenge E&Ps face in today’s oil patch is getting to a double-digit increase in return on capital employed (ROCE) in a sub-$50 oil environment. With completions now representing more than 60% of well cost, E&Ps are pursuing capital efficiency by improving well productivity to offset inflationary cost in oil services.

My Generation completions upend the old debate on net present value (NPV) vs. EUR by moving from a zero-sum either/or argument to a pie-expansion theorem that claims more of both.

The latest My Generation wells, typically defined as Third Generation completions, employ 1,700 to 2,500 pounds of proppant per lateral foot vs. 1,000 pounds or less on earlier wells. Simultaneously, stage spacing dropped 20% year-over-year in second-quarter 2017 to roughly 200 feet in nearly all plays, according to Hart Energy’s Heard in the Field survey program. Leading edge E&Ps are testing stage spacing down to 150 feet in natural gas plays.

Not to be forgotten when it comes to ROCE is the ability to capture efficiency by reducing the time it takes to get wells turned in line.

Continental Resources Inc. (NYSE: CLR) recognized an additional $2 million in revenue in Oklahoma’s Mississippian play during the first six months of a well’s life as the company accelerated NPV by reducing the spud-to-first production cycle. Savings originated in part from cost reductions as drilling rigs rolled off expensive legacy term contracts into lower spot market pricing at the same time pad drilling increased individual rig productivity.

Multiplying those gains across multiple wells on a single pad provides a hint at where My Generation techniques are headed.

In the Permian Basin, experiments with simultaneous completions of multiple laterals on single pads suggest the industry is on the threshold of significant productivity enhancement as the completion cycle addresses full-field development in tight formation plays.

Energen Corp. (NYSE: EGN) defines this process as pattern wells. Pattern well completions sustain downhole reservoir pressure across all wells on a pad vs. the traditional fall off between a parent well and subsequently drilled child wells that has become an industry vexation.

Typically, E&Ps drill a parent well and return to the pad months later to complete child wells. The parent well tends to be the most productive well out of the set while child wells seldom produce the same volume due to reservoir pressure depletion and interference between wells.

During its first-quarter 2017 earnings call, Encana Corp. (NYSE: ECA) also reported a performance boost using multiwell batch completions on single pads in the Midland Basin.

For perspective, less than 40% of Midland Basin wells and 15% of Delaware Basin wells currently employ batch completions on a single pad pattern well basis, according to comments Energen made in its second-quarter 2017 earnings call. That suggests E&Ps will be talking about iterations on My Generation wells for some time to come.

Richard Mason can be reached at rmason@hartenergy.com.

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