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Unconventional Yearbook 2018

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UGcenter.com | January 2018 | 59 DOWNSPACING | 2018 UNCONVENTIONAL YEARBOOK rate of return, from 40% to 80%, compared to the previous type curve EUR. Continental also lowered its Bakken well payout period from 2.5 years to 15 months. "We're generat- ing $2 million incremental cash flow per well in the first year—providing more profit to working inter- est owners, royalty owners and the state of North Dakota," Gould said. "Continental-operated oil production is up 35% in just the seven months from January to August this year. The average 24-hour IP for our 57 gross operated wells in third quarter is 1,750 boe/d, with 80% oil. That is a strong average in terms of both quality and quantity." Gould said the unit development approach is pervasive. "We evaluate our operations, as well as our partners' and industry operations, in order to determine the optimum well density to maximize PV10 for unit development," he said. "We looked at well-by-well economics as we were broadening our acreage position a few years ago. Now that we are in the early stages of full development, we analyze economics by unit and develop all the wells at one time. So our question is, 'What is the optimum well density, completion and production design to maximize PV10 of the entire unit?'" Continental completed three wells in third-quar- ter 2017, two in the Middle Bakken and one in Three Forks, that are in the all-time top 10 initial production rates for Bakken producers for their company. "They're spread out geographically and all of them used optimized completions," Gould said. Downspacing and other components of the company's optimized completions have built up Continental's operating inventory. "We estimate we now have over 4,000 gross operated locations remaining in the Bakken," Gould said. "We esti- mate that we could reasonably drill only about half of this inventory in the next decade, assuming an average rig count of eight to 10 rigs. We believe that this inventory could deliver a blended rate of return of 60% to 80%, assuming $50 to $55 WTI oil prices." While tighter vertical and horizontal spacing is key to this resource management, there are other factors. "The main characteristics of optimized com- pletions are higher proppant loads averaging 1,000 pounds or more per foot, shorter stage lengths as short as 150 ft, and diverter technol- ogy to distribute the proppant during comple- tion," Gould said. "On the production side, we're flowing back more aggressively and using electric submersible pump technology to generate higher production rates upfront." Continental went to slickwater fracks in 2014 and uses a variety of completion contractors. "Competition is a great way to reduce costs, increase operational efficien- cies, and keep up with the latest technology," he said. "We also learn by monitoring our partners and other operators." Pat Bent, the company's senior vice president of drilling, points to design changes from rigs to bits that result in cost savings. "Compared to 2014, we cut our drilling time in half," Bent said. "We now average 10.5 days per well, spud to TD in the Bakken. Cycle time decreased dramatically through a combination of technology and teamwork. We have a command center on every well that includes engineering, geology and others co-located for real- time data decision making." Lateral drilling rates of 3,400 ft/d are common. "We've drilled 2-mile laterals in two days," Bent said. Continental maxi- mizes use of its pad footprint, drilling as many as 25 wells from one location. "We've accessed reserves that were previously inaccessible, such as under a lake," Bent said. In this early-stage density test environment, Continental is one of the pioneers in running pilot Continental Resources Ludwig Unit density drilling project is in the Stack play in Oklahoma. (Photo courtesy of Continental Resources)

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