Half of well productivity gains may be due to location – not better frac design ?

Much has been made of productivity gains in oil and gas since the crude oil price plunge beginning in the second half of 2014.

Much of the improved output, the industry touts, has been attributed to improved completion designs. Higher proppant loading, tighter spacing, laterals measured in miles rather than feet, among other variables, have certainly yielded more productive wells.

More to productivity gains

However, some industry watchers believe there is more to productivity gains than more proppant, tighter spacing and longer laterals.

Ask a real estate salesperson what the key is to property sales and the mantra is “location, location, location.”

A recent study by researchers at the Massachusetts Institute of Technology’s Energy Initiative (MITEI) postulates industry “sweet-spotting” — drilling in the most productive locations within a play — isn’t being properly considered in current production forecasts.

Where, not how

Their research indicates nearly half the productivity gains in one of the U.S.’s major oil plays since 2014 was due to where companies were drilling – not how they were drilling, Kallanish Energy understands.

One of the first moves producers made when the bottom started dropping out of gas and particularly crude prices, was to pull in their proverbial horns, and concentrate their resources in what’s known as a play’s “sweet spot,” the best rock, a play’s core.

Using well results from the Bakken play, the MIT researchers attempted to gauge the effects of “sweet spotting.” Using a modeling system called regression-kriging, or RK, the researchers believe they have identified the effects of location.


“Sweet-spotting, also called ‘high-grading,’ might be a profitable strategy in the short-term, but will not be possible once these areas have been exploited,” the MITEI researchers believe. “It is critical to be able to accurately forecast future productivity levels by separating the role that technology plays in well design from the geological influence inherent in sweet-spotting strategies.”

Justin Montgomery, a graduate student in civil and environmental engineering who is also a MITEI researcher, and Francis O’Sullivan, MITEI’s director of research, describe the application of a statistical approach that can reliably distinguish between the impact that changes in well location and technology have on the productivity of a well.

“There has not been a rigorous attempt to disentangle the effects of technology and sweet-spotting,” Montgomery told MITEI’s news bureau. “We realized that there was an opportunity to both provide a better understanding of what this balance has been in a particular tight oil basin and at the same time present a methodology that can be used in other basins.”

Montgomery and O’Sullivan tested five different models using data pulled from a 42-month period, including nearly 4,000 wells drilled into North Dakota’s Middle Bakken and Three Forks formations, the primary oil- and gas-producing layers of the Williston Basin.

Beginning with models based on current industry practice, the researchers found these approaches each offered different levels of complexity to control for location. This is important since important geological properties in shale and tight oil formations vary considerably over even short distances. What all of these approaches imply is the variation in these spaces can be neglected at a certain point without overly influencing results.

But Montgomery and O’Sullivan discovered this isn’t necessarily true. These models, one of which is currently relied upon by the U.S. Energy Information Administration for developing its Annual Energy Outlook forecasts, have a tendency to significantly overestimate the impact of technology because they are not flexible enough to account for short-distance locational variations present in the data.

In the Bakken and Three Forks of North Dakota, for instance, they found half of the gains in average well productivity were actually due to changes in where companies were drilling wells, rather than how they were drilling them.

This means current forecasts for future production and cost of tight oil and shale gas resources in the U.S. may be overly optimistic due to unrealistic expectations of future technology-driven productivity gains.

The researchers are quick to say their results do not suggest that more intense completions are not yielding better wells, just that some of the recent productivity gains are location-driven.

Only so much core to drill

Other models, like those commonly used in the industry and government agencies, typically underestimate the effects of location.

The difference is, while improvements in technology can generally be applied to operations throughout the field, there is only so much core acreage available to drill. The implication is that future wells may not be as productive as previously forecast, once the best of the best acreage has been drilled and companies move out of the core into less productive rock.

According to the MITEI researchers, overlooking location can cause companies to overspend on completions. If a forecasting model does not include the effects of location, it will put excessive emphasis on improving completion designs. This could cause companies to spend more than necessary on a completion design in non-core areas on the assumption that such a well will perform as well as a core location with a similar design.