Eagle Ford Analog

When imagining a sophisticated modern laboratory, few envision a facility like the scrub-brush open prairie of South Texas. But a review of best practices among operators and service companies in the Eagle Ford shale illustrates how the oil and gas industry adapts to a changing environment over time, whether that environment is commodity price volatility or geologic targets.

True, the number of steel-toed boots and weathered hard hats in the Texas cities of Gonzales, Karnes City, Yorktown or Cotulla far outpace the number of white laboratory coats. But a combination of white lab coats and steel-toed boots has produced significant gains in efficiency and well productivity since the late, great Petrohawk Energy Corp. drilled the modern-day Eagle Ford discovery in LaSalle County’s Hawkville Field four years ago.

The question is whether efficiency gains have played out, or whether operators and service companies can pull another rabbit of innovation out of their collective hard hats.

Those topics were the subject of a technology panel involving representatives of Baker Hughes Inc. and Halliburton Co. on the services side and Pioneer Natural Resources Co. and ConocoPhillips on the operator side at Hart Energy’s third annual DUG Eagle Ford Conference and Exposition in San Antonio held in mid-October.

While technology sessions can devolve into arcane ruminations about gamma rays, cased-hole completions, short bit-to-bend downhole motors or zipper fracs, panelists at DUG Eagle Ford took a philosophical approach to defining where the industry is currently—and where it can go. Whether the benefits of innovation have been fully captured, or still offer additional gains is an intriguing question because, unlike Las Vegas, what happens in the Eagle Ford will not stay in the Eagle Ford—or even stay restricted to the U.S.

Illustration by Robert Pizzo

The verdict among Eagle Ford panelists is that the industry has reached a temporary limit with existing technology and work processes, particularly on the drilling side, where cycle times have dropped significantly and operators are finding they need fewer rigs to achieve their program goals as they switch to pad drilling.

“Unless there is a design change or a paradigm shift, we’re getting close to reaching our limits,” said J.D. (Joey) Hall, vice president, South Texas asset team for Pioneer Natural Resources.

Hall cited several developments, including the move to pad drilling and zipper fracs, blending information from seismic and logging to place well laterals in the most optimum locations, and tool innovations involving downhole motors and bits. Some discoveries have been serendipitous for Pioneer, such as employing back builds in horizontal laterals that reduce torque and drag and increase drilling speed, Hall told conference attendees.

“Certainly the law of diminishing returns is in play,” said James King, director of applications engineering for Baker Hughes. “Advances in bits and advanced land-based rotary steerable systems have helped on the drilling side.

“On the completion side, plug run in speed has been maximized. The engineering part of that solution has been found, and we can run as fast as you want to go.”

King noted that the focus has turned to risk mitigation in completions now that operators and service companies have maximized the speed at which drilling and completion cycles unfold.

“The limitation is really a statistical question. What risk are you ready to take and what are your procedures for insuring you can run in hole at higher speeds? Once you reach 600 to 800 feet per minute, you’ve reached the limit, but you’ve also added risk,” King said.

Back to the future

The Eagle Ford is entering a mature phase of development as operators move into broad-scale resource harvest. Proper well spacing for the most optimum harvest is as much a subject for discussion as technical issues. On a larger scale, the Eagle Ford has become an analog for the transformation under way in tight formation oil and gas.

That transformation involves two themes. The first is a transition from gas as the main target in unconventional development to oil and liquids-rich basins. The Eagle Ford is blessed with all three commodities. What started as a gas play in late 2008 transitioned to a gas condensate/liquids play after January 2011 with delineation work now focusing on the oil window as 2012 comes to a close. That complexity sets the Eagle Ford apart from single-dimension tight formation plays like dry gas elsewhere.

Secondly, the Eagle Ford is a model for how technology allows operators to improve productivity, lower well costs, and increase yield across the commodity spectrum as the industry unlocks the geologic and engineering puzzle for oil and natural gas liquids. The broader evolution toward tight formation oil and gas reflects the irony inherent in the homily that tight formation plays are homogenous in their heterogeneity. In other words, what makes tight formation oil and gas plays alike is the fact that they are all different.

To place the Eagle Ford in perspective, it helps to recall the unconventional gas cycle, which established the model for tight formation plays. It began with the Barnett shale, where horizontal drilling and multistage fracturing made the gas play economically viable seven years ago. But the Barnett was really a 19-year story that became an overnight success once operators figured out the technological tandem of horizontal drilling and multistage slickwater fracturing.

Oil and gas operators successfully exported those techniques to dry-gas plays in the Arkoma Woodford in Oklahoma, the Fayetteville shale in Arkansas and eventually to the Haynesville and Marcellus shales. A similar process was under way in the Horn River and Montney shales in Canada.

The upshot was that the industry created a tight formation development model that shrank the evolution from discovery to development into a three-year cycle. The land grab in the first year begat delineation, which begat optimization—the field laboratory experiments that unlocked the engineering and geologic puzzles—in year two, which begat resource harvest, or the efficient extraction of hydrocarbons scattered across a geologic play by the end of year three. Think of it as the oil and gas industry’s definition of instant gratification.

But those developments were focused on dry gas, which, as a molecule, is petite, agile, and athletic enough to escape nano-darcy permeability with hydraulic fracturing. Oil molecules are a different story. Think of harvesting oil molecules in tight formations as similar to coaxing a large, slow un-athletic commuter off a crowded bus. In other words, what works in dry gas does not always work in liquids or oil and the Eagle Ford is providing the industry an opportunity to develop techniques across the commodity spectrum.

“We’ve learned so many things going from the Barnett to the Fayetteville and the Haynesville,” said Bill Melton, Halliburton’s completions business development manager for South Texas. “Sometimes you have to wipe the slate clean. People trying to import a particular design, say a high-rate slickwater frac design that wasn’t appropriate for the reservoir dynam- ics in the Eagle Ford, may have delayed early success, but as people understood their rock a little better and understood what stimulation design delivered the best results, you saw the speed of optimization and success pick up and I think we are in that phase right now.”

The question is whether the industry can take it further, and whether those attempts lead to improvements in other oil or liquids basins in the U.S. and internationally.

Focus shifts to completions

Dave Cramer, a completions engineering fellow at ConocoPhillips, told conference attendees that the emphasis on efficiency gains is switching from drilling to completions.

“On the drilling side, I see things really flattening out,” he said. “On the completions side, there are things on the tool end, for example reliably being able to open up sleeves, that would knock off hours per stage and allow us to do fracture treatments quicker and be more efficient. I do see some technological innovations the industry is working on right now that will allow us to be more efficient in hydraulic fracturing.”

Part of that involves becoming more efficient in the fracture stimulation process itself. Panelists noted in various ways that the standard model of spacing fracture clusters at regular intervals along a horizontal lateral embedded inefficiencies into the process. Not all stages were effective, leading to a waste of water, proppant, hydraulic horsepower, and adding cost without return on wells that routinely exceed some $8 million.

“Right now the challenge with a multiple cluster design in conventional plug and perf is: are we equally treating every interval of the rock and how do we maximize the amount of reservoir that we are actually contacting?” said Halliburton’s Bill Melton.

“So a number of MWD (measurement while drilling) and LWD (logging while drilling) technologies can be developed and run efficiently and reliably to characterize a reservoir and allow us to start optimizing where we put our initiation points along the length of the lateral instead of evenly spacing things out.”

James King outlined how better measurements and better reservoir modeling will soon help operators improve decision making on downhole engineering.

“Going forward what we will see, short of a dramatic paradigm shift, is an improvement in the effectiveness of extraction from reservoirs to increase profitability for operators. That will come from visualization, evaluation and simulation,” he said.

In other words, it involves the industry evolving from brute force—more water, more sand, more hydraulic horsepower—to finesse in completing portions of the reservoir most likely to yield the best production. The need is there, according to Pioneer’s Joey Hall.

“Some of the things the service companies are doing that I’m very hopeful for are not just the evolving technology of execution, but rather the evolving technology for prediction. How do we model fractures? As I talk to my team, unanimously the one thing they say needs development is the predictive tools to help us manage the process better so we can try things on a computer versus trying things in the field. I think some of the predictive tools are key to progressing things,” he said.

The Eagle Ford shale has served as a lab for technology innovations now being transferred to liquids-rich tight formation plays such as the Granite Wash, shown here.

Ultimately, the takeaways from the DUG Eagle Ford technical panel were both implicit and explicit. Implicitly, the concept of peak oil has been postponed by perhaps half a generation as the industry unlocks the secrets to tight formation oil and gas production.

Explicitly, efficiency gains are accelerating the development of each new geologic play, whether gas or oil. Several factors support cycle acceleration, which has potential global repercussions. For one, knowledge is transferring more quickly within oil and gas companies and oil services companies.

ConocoPhillips Dave Cramer outlined how a company with global reach captures learnings and disseminates them to staff via well symposia and networks of excellence. On the services side, both Halliburton and Baker Hughes employ internal seminars, promote cross pollination through common training programs for new hires, maintain companywide databases of case studies and rely on the human aspect that links employees who have worked in multiple basins.

The result: the pace of information flow is accelerating.

“I find that a lot of younger employees think in terms of iPads, blogs, and wikis, and information exchange is much, much faster than it was when we all used to go to packer school or liner hanger school for two weeks every couple of years,” said James King.

“I’m seeing information transfer is lightening fast compared to just five years ago within our organization, and I am sure other organizations are transforming in the same way. It is really a new world. The digital oil field is within our grasp. It is coming, and it works.”