HOUSTON—Technology ushered in the U.S. shale revolution, and technology will be crucial to propelling the oil and gas industry forward as companies experiment with completion designs, proppant levels and data analytics among others to get the most from reservoirs.
That was the sentiment of speakers who spoke about technology and techniques during KCA’s latest energy breakfast.
“Technology is key to continuing the advancements and the efficiency gains to attract more hydrocarbons at a much lower cost to compete in this lower for longer price environment,” said Nathan McMahan, director of unconventional reservoirs, ConocoPhillips (NYSE: COP).
However, the challenge is figuring out how to keep advancing, taking lessons learned in core areas and adapting these to noncore areas of the play as well as transferring knowledge to new areas, McMahan said. It will take the type of thinking that sparked the shale revolution—the combination of two old technologies (hydraulic fracturing and horizontal drilling)—to keep progressing.
The combo, combined with other drilling advancements, has pushed oil production to about 4.9 million barrels per day and gas production to more than 49 billion cubic feet per day in seven shale regions alone, according to the U.S. Energy Information Administration’s Drilling Productivity Report. However, steep declines and low recovery rates mean there is still work to do.
Recent trends indicate operators and service companies are thinking outside of the box and experimenting with different methods and techniques to grow production.
Completions have doubled, tripled and even quadrupled, in some instances, in the amount of proppant and number of stages, McMahan said.
“There’s been a rapid experimentation going on in the last five years. We really don’t understand all the physics and mechanisms behind it,” he added. “The drillbit is really leading the way. The analysis tools and the techniques are still trying to catch up, but this rapid experimentation is getting quick results, quick feedback and we’re finding the trends.”
ConocoPhillips has gone from pumping about 3.8 million pounds of proppant with 75 clusters to about 15.5 million pounds of proppant and 300 clusters.
McMahan added that “longer laterals have really gone vogue in the industry” as well, with drilling contacting more rock with one well to increase production rates. Many are eyeing 10,000-ft laterals, if they haven’t already reached such lengths. He called this trend a game-changer, considering the potential for more payout from multilaterals.
Then, there is data analytics, which is being used to identify trends in the oil patch so successes can be replicated elsewhere. It’s already having a positive impact on drilling times for ConocoPhillips. It used to take 30 days to drill a well. That’s down to 15 or less. “With the same amount of rigs, we can now drill twice the wells.”
Capital budgets that have shrunken in recent years due to the downturn means there will be more of this type of low-cost experimentation with quick feedback that enable quick implementation, according to McMahan.
Marc Davidson, senior director of technology for Halliburton, said the company sees opportunities to apply technology in all asset types as the industry rebounds from a downturn that knocked the U.S. rig count down 79% and left more than 350,000 workers without jobs, including 40% of Halliburton’s workforce.
“Despite these conditions, Halliburton continued to invest in technology development through the downturn,” Davidson said, adding a recovery is underway. “The investments that we’ve made in technology during the downturn have positioned us well to collaborate with our customers and maximize their asset values as the market recovers.”
The oilfield service company aims to drive down costs per barrel of oil equivalent by focusing on drilling optimization, the supply chain and surface efficiencies, which Davidson called the numerator. Examples include Halliburton’s depth of cut drillbit technology to increase rate of penetration, Illusion Frac Plug to lower costs, time and risk related to conventional composite plug removal, and its ExpressKinect wellhead connection units that enables single-line rig-up to wellheads for safer and more efficient operations.
However, the other part of the equation—the denominator—has received less attention in the industry, according to Davidson. It involves hydrocarbon recovery factors, which he said are in the single digits. “Even a modest improvement would have a substantial impact on our customers’ asset values,” he said. “The most successful companies in the unconventionals are those that have taken time to understand their reservoirs better.”
Variables in the denominator involve maximizing production. It begins by gathering and improving subsurface insight, and using this knowledge in the area of custom chemistry to engineer stimulation fluids and improve completion processes, he added. Lessons learned could also be applied to full-field development.
Among the technologies that can help companies with subsurface insight are integrated sensor diagnostics (ISD), which are used to devise plans for well spacing, well placement, fracture spacing and completion design.
“ISD starts with sensor acquisition. Fiber optics provides near-wellbore data and microseismic sensing, sometimes augmented with microdeformation technology, provides far-field data,” Davidson explained. “After the data is interpreted and integrated, the diagnostics allow us to calibrate fracturing and reservoir models based on the measures subsurface responses. Fiber optic information allows us to constrain the near wellbore results, such as stimulation cluster efficiency and production, and microseismic results define the far-field fracture geometry and complexity in the model.”
The calibrated reservoir model can be used for further analysis to help understand how changes in well spacing, well placement and other designs could impact recovery. It can also be used to evaluate the effects of bypassed reserves and potential well interference, he added.
“Executing an ISD project early on in the field can significantly reduce the long-term capital requirement to reach optimization for full-field development,” Davidson said.
One operator in the Utica, working with Halliburton, deployed permanent fiber optics and microseismic mapping for stimulation model. The operator carried out calibration and reservoir modeling to evaluate its lateral spacing. “Based on the ISD results, they reduced their well spacing and were able to design completions to target 25% more reserves,” he said.
By implementing ISD and applying custom chemistry the industry has a chance to increase recovery, maximize the value of assets and advance technology in today’s environment, Davidson added.
Velda Addison can be reached at firstname.lastname@example.org.