SAN ANTONIO—Everyone expected alternative energy to be the big story of the 21st Century. However, the successful development of unconventional reservoirs delivered what Greg Leveille, chief technology officer for ConocoPhillips (NYSE: COP), described as an “energy miracle.” Contributing to that miracle is the resource-rich Eagle Ford Shale and the “enormously important role” it played in shifting the U.S. from the role of energy importer to energy exporter.
“Today the U.S. is the world’s largest producer of hydrocarbons at 27 and a half million barrels of oil equivalent per day, we are well ahead of Russia, which is just a bit over 20 million barrels of oil equivalent per day,” said Leveille before a packed crowd at Hart Energy’s DUG Eagle Ford Conference. “We produce about twice as much as Saudi Arabia, and no other country in the world produces more than 10 million barrels of oil equivalent per day, so an amazing result.”
For evidence of the Eagle Ford’s prolific potential look to its production history. In a span of roughly five years, production shot from less than 0.5 million barrels of oil equivalent per day (MMboe/d) in 2010 to 2.5 MMboe/d in early 2015, according to Leveille. While the drop in oil prices caused production to fall to below 2 MMboe/d in 2017, it didn’t stay down for long as production is growing again at a “very rapid pace,” he noted. The Eagle Ford is the one of the top three unconventional oil plays in the U.S., behind the Marcellus Shale and the Delaware Basin.
“The Eagle Ford was just recently passed by the Delaware Basin. Of course, the growth in of the Delaware has been astronomical, a few hundred rigs out there drilling wells, and of course, the Marcellus on the east coast is a monster natural gas play,” he said. “But if you look at those top three players, although the Eagle Ford is not today the largest producer of oil, we would argue it's one of the best unconventional reservoir players for producing value per dollar invested.”
For ConocoPhillips, the Eagle Ford is the company’s first horizontal shale play in its history. With approximately 210,000 net acres primarily in DeWitt, Karnes and Live Oak counties. The shale play has “some areas with extremely good rock with extremely good reservoir quality, areas where you can get the production that has a cost supply down in the twenty dollar per barrel range,” he noted.
“Our primary mission as an oil and gas operator is to acquire acreage in those areas with the very best rock,” he said. “We did a fairly good job of doing this in that our two hundred thousand acres are located mostly in the best part of the Karnes and DeWitt county sweet spots.”
The good acre position paired with a “relentless focus on lowering cost of supply,” led the company to secure the top spot among Eagle Ford operators. For ConocoPhillips, it is $25/bbl as compared to the $30/bbl-plus cost of supply for other area operators, according to his presentation.
“It's been an area which has been incredibly productive for ConocoPhillips and an area which has been incredibly important for the company,” he said.
Along with an optimal pace of development, four technologies have been key to the company’s success in keeping the costs of supply low for its fields. The company’s “Drilling Execution Efficiency Platform” and the use of digital acoustic sensing to optimize completions are two of the four. The remaining two go far in demonstrating the scientific and experimental approaches that are delivering returns for the company.
Understanding the Eagle Ford’s hydraulic fracturing characteristics is another key. The company drilled and fractured a development well and then acquired a core from that fractured reservoir to accomplish this, according to Leveille. The company acquired core imaging logs from several wells, and from a review of all, a new picture emerged.
“We were able to ascertain what hydraulic fractures actually look like and it turns out they look almost nothing like what the mathematical models that predict fracture geometries suggest they should look like,” he said. “With this information, we were able to rapidly evolve our completion time.”
Understanding the vertical draining within an Eagle Ford well through a geochemical sampling of the oil is also a key.
“You’d like to know how high your fractures are reaching so that you can understand how many layers of wells you should put into the reservoir,” he said. “This criteria allows us to understand the drainage from the reservoir over time very precisely and with that, then optimize placement of wells into that reservoir.”
By understanding and using all of these key technologies, the company has consistently improved upon its well completion designs that are in turn, delivering increases in per well output and recovery, he noted. For example, in 2012 the company’s Vintage 1 design pumped 3.8 MMlb of proppant downhole at 750 lb/ft with a 70 ft cluster spacing evolved into the Vintage 4 design in 2017 with significantly more proppant used.
“We went from a moderately modest scale of proppant volume [in 2012] to today pumping somewhere between fourteen and seventeen million pounds of proppant in a 5,000 ft long well, larger volumes as you scale up to longer lengths,” he said. “We've also increased the curve cluster density, we've optimized the methods of placing that proppant.”
The impact of these adjustments is visible through the enormous improvements in production rates for the company.
“If you went back to 2012, in about three years’ time, you'd produce around a third of a million barrels of oil equivalent. Today, in less than a year we're producing that same volume, and the ultimate recovery from these wells has also gone up significantly,” he said. “We’re working on a vintage five completion right now, which we think has the possibility of giving us another uplift from where we are.”
Understanding the complexity in the geology of the Eagle Ford is yet another key in unlocking the full potential of the resource play. For example, understanding how the organic matter concentration changes within the reservoir and where the best rocks are located factor greatly into the optimization of the well placement and in the optimization of production, he noted.
“We’ve been able to determine with a high degree of accuracy the vertical drainage, and from that, we were able to understand how many wells are needed in the different areas,” he said.
Assisting in the development of that understanding is the company’s approach to data analytics and how it is applying it to understand complex problems in ways that were difficult to do in the past.
“At ConocoPhillips, we see data analytics as a tool that every one of our employees is going to use to be more productive. We do not see this as something that is necessarily replacing humans; it supplements a human's capabilities as they can get more work done in a much shorter period,” he said.
“For example, if you went back just a few years, it took us over 20 days to go from spud-to-spud on a well in the Eagle Ford. Today it is now around 12 days, and a huge part of that improvement is the use of data analytics to understand how to optimize every single operation involved in the drilling of an Eagle Ford well.”
The company is using data analytics in essentially all of its operations around the world, he noted, adding that in all of those operating areas—from Alaska, the North Sea or in the Asia Pacific—where the use of data analytics is having as big of an impact as it is in unconventional reservoirs.
“Ours’ is an industry drilling tens of thousands of wells a year. From those wells, we’re extracting enormous amounts of data that can then be analyzed,” he said. “That data along with modern analytics tools are enabling us to gain insights that would be very difficult to gain with the tools of the past. So today is a very exciting time.”