Bill Thomas, chairman and CEO of the independent oil and gas producer, explained how the company has drilled and completed the best Bakken well in the history of the play. Using its high-intensity design, EOG drilled and completed a well—Riverview #102-32H—in its Antelope field area that produced 200,000 barrels of oil in its first 91 days for an average daily production total of roughly 2,200 bopd.
Although the well is still on confidential status, Thomas said the well’s results are “definitely repeatable.” The horizontal was drilled at only 4,600 feet, only half of the typical length for most Williston Basin wells.
The process used is similar to that of EOG’s Eagle Ford approach to completing wells. Instead of the 540 fracture events per 1,000 foot of lateral EOG accomplished in 2010 wells, its 2015 wells are completed with 4,030 fracture events per 1,000 feet. According to Thomas, the new approach generates 8 to 10 times the number of fractures within 1,000 feet when compared to the old method. Containing fracture events closer to the wellbore is crucial for EOG. It now works to keep fractures within 200 to 300 feet of the well bore. “It allows us to downspace and drill wells closer and closer together,” he said. In addition to wellbore proximity for fractures, the drilling teams are working to keep the bit within a 20 to 30 foot window instead of the traditionally accepted 100 to 150 foot drilling window.
The use of fluid diverting agents is also a key to its high-density design, Thomas said. EOG uses in-house data and information for all drilling and completion designs.
EOG’s version of the high-intensity fracture has helped it to add to its estimated ultimate recovery oil levels in the Bakken and in Texas. Earlier this year, EOG updated its Bakken and Three Forks net resource potential estimates to just over 1 billion boe. In the Delaware Basin of Texas, EOG just upped its resource potential estimates to 1 billion boe as well.
Regardless of its breakthroughs in high-intensity fracks—a process Thomas said the industry has not caught up to yet—EOG will only seek to keep production flat in 2016. “We are going to be very disciplined next year and spend within cash flow. I believe it will take $60 oil to get the U.S. back in growth mode,” Thomas said.
Packers Plus last month announced that it successfully completed multiple wells in North Dakota’s Bakken formation using its advanced high-frack intensity systems. Themig believes that this technology—in combination with multilateral wells and zonal isolations—have the potential to significantly change the economics for Bakken producers.
The 50-stage wells are the first step in the process. Themig said the second step will be wells with 60 to 70 stages—uninterrupted with no intervention. The third level will go to 100-stage jobs with two- to three-mile laterals.
“One of the things you’re starting to see from our company and is economic high-stage count and economic high-frack intensity,” Themig said. “We don’t think it’s plug and perf. We believe the open hole has some distinct advantages in this play. We have the curves to prove it in almost every basin.”
Themig is so confident that he predicts there will eventually be a sustained level of drilling in the Williston Basin that’s less dependent on the oil price structure.
“We think there are other technologies people should be using and will be using in North Dakota,” he explained. “I have some studies in the Williston Basin with four or five years of data that show just by getting effective isolation, you can change the ultimate recoveries in a field by roughly 50 percent, and that alone changes the economics of the Bakken.”
Although the price of oil will continue to play a role in the level of oil and gas activity in the Willison Basin, technological innovation—which Themig said has driven the industry for the past 10 years—will have a significant impact. He said the company’s technology would provide immediate benefits in the core of the Bakken and benefit wells in the play’s second-tier areas at $40 to $45 a barrel.
Enhanced Oil Recovery (EOR)
EOG confirmed success of its internally developed EOR process in the Eagle Ford following more than three years of testing in four successful pilot projects with 15 producing wells. These four pilot projects, located across the field, demonstrated consistent reservoir responses from a group of mature producing wells. The pilots generated significant increases in crude oil production with relatively low capital cost. One additional EOR pilot project that encompasses 32 producing wells is planned for 2016.
EOG anticipates many benefits from the application of this new technology, including high incremental net present value and rates of return on investment, low finding and operating costs, reduced severance tax rates, lower production decline rates and increased reservoir recoveries. EOG's Eagle Ford shale acreage position possesses unique geologic properties ideally suited for the company's proprietary EOR techniques. These methods require very strong geologic containment that may not exist in most horizontal oil plays.
"Today's introduction of EOG's enhanced oil recovery potential for the Eagle Ford shale is another technical breakthrough to further enhance the value of EOG's Eagle Ford assets," Thomas said. "Our proprietary EOR capabilities and first-mover advantages uniquely position the company to create substantial incremental shareholder value through this long-life project."
South Texas Austin Chalk
EOG expanded its inventory of high rate of return crude oil plays with successful drilling results in the South Texas Austin Chalk, which sits on top of the South Texas Eagle Ford shale. The initial test well, the Leonard AC Unit 101H, came online with average 30-day initial production rates of 2,100 barrels of oil per day (Bopd) with 295 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.9 million cubic feet per day (MMcfd) of natural gas. A second Austin Chalk well, the Denali Unit 101H, was brought online in April 2016, with average 20-day initial production rates of 2,265 Bopd with 415 Bpd of NGLs and 2.7 MMcfd of natural gas. EOG intends to drill seven additional Austin Chalk wells in 2016 to further delineate the formation's potential.
"EOG continues to demonstrate its organic growth capabilities by discovering a new geologic concept in an existing play," Thomas said. "Although the industry has known about the Austin Chalk for many years, it took a new approach to turn it into a high rate of return play which competes with EOG's top-tier assets. We expect the Austin Chalk to make a meaningful contribution to our future success."