It is no secret that technology is the key to unlocking hydrocarbon resources.

For ConocoPhillips, which plans to increase development spending by about 50% on North American unconventionals in the next three years, technology will be crucial to growing production and its value, especially in times of lower, more volatile price environments.

The company hopes to do just that with pilot studies aimed at optimizing recovery in the Eagle Ford Shale, Canadian oil sands and elsewhere.

“We need to advance our understanding of the science of how unconventional reservoirs work in order to do that,” Al Hirshberg, ConocoPhillips’ executive vice president of technology and projects, said during the company’s analyst and investor presentation April 8.

He highlighted the company’s stimulated rock volume (SRV) pilot project in the Eagle Ford. There, drilling and completion (D&C) gains include a 30% drop in the D&C cost per well, a 30% increase in the EUR per well and a 40% drop in the spud to production time as the number of clusters doubled to 150 from 2013 to 2015.

As part of the SRV pilot, ConocoPhillips is logging and coring reservoir rock around a horizontal producer before and after fracture stimulation.

“Think of it as trying to take a CAT scan of the rock,” he said.

The goal is get a better picture of the fracture network, reducing downhole guesswork that is rather commonplace today among the industry’s shale players.

“Why do we care about the fracture network geometry?” Hirshberg asked. “Characteristics of this fracture network and the detailed geometry of what it looks like drives the rate of production you get from these wells and the ultimate recovery that you get from these wells.”

Using three computer models, each with a different set of assumptions on the frack geology’s appearance, Hirshberg pointed out red areas depicting high hydrocarbon recoveries and blue areas illustrating where recovery was either low or non-existent.

By using the CAT scan-like technology, the company hopes to better understand geology and adjust well spacing and completion designs for more production and higher recoveries.

While the technology is still in its early stages, ConocoPhillips is seeing cost-savings with proven technology at Surmont, its oil sands steam-assisted gravity drainage facility in Canada.

“We’ve already reduced our average well costs at Surmount 2 by 30% just by employing some of these new technologies,” Hirshberg said, after mentioning the company’s 2014 goal to reduce cost of supply by $20 per barrel (bbl) before moving forward with any new oil sands development. So far, the company has achieved $12 of that $20 with technologies such as flow control devices, which are placed in the wellbore to get better control over where steam flows.

Having uniform steam chamber growth is essential to maximizing recovery and production, he explained, comparing the results of two wells, one of which did not have flow control devices.

After 60 months, the well with flow control devices had uniform steam chamber development.

“In fact when we test this in the field we get about 50% higher production from the wells with the flow control device in them, and that results in lower steam/oil ratios and lower greenhouse gas emissions for each barrel of production,” Hirshberg added.

The company is working on additional technology to further drive down costs at its oil sands operations. These include gas turbine cogeneration technology enabling the facility to generate its own power, a cheaper alternative to taking it off the grid. The process was tested in a 2014 pilot project at Surmont, resulting in a 15% reduction in energy cost and a 60% reduction in NOx emissions.

Offshore, ConocoPhillips is teaming up with its peers to develop 20,000 psi subsea technology, needed as operators drill deeper and into more HP/HT environments in their search for oil and gas. Such technology, which will be designed to withstand 20,000 psi pressure and 177 C (350 F), will be needed for discoveries in Paleogene-aged reservoir sands. These include the BP-operated Gila discovery (ConocoPhillips, 20% working interest), found after a well drilled to a depth of 8,907 m (29,221 ft) on the Keathley Canyon Block.

The unified effort, which includes sharing costs and agreeing on standards for the equipment, is a rarity for the industry’s deepwater sector, he said.

“This work is pretty well advanced now and I don’t think it's going to pose any impairment to development of our discoveries in the Paleogene,” Hirshberg said.

Contact the author, Velda Addison, at vaddison@hartenergy.com.