HART ENERGY reports that Whiting Petroleum Corp. (NYSE: WLL) made a 10,000 barrels of oil equivalent per day (boe/d) pad in the Williston Basin, bringing on the three-well pad in February with IP rates averaging 3,509 boe/d per well. Jim Volker, chairman, president and CEO, revealed the details of the two-section Loomer 44-33 pad in a keynote speech at Hart Energy’s 2017 DUG Bakken & Niobrara conference, held during the week of March 13 in Denver.
The Loomer TFH had an IP rate of 3,005 bbl of oil and 4.584 million cubic feet (MMcf) of gas, according to the North Dakota Industrial Commission, which removed the wells from confidential status. Loomer 2H had an IP rate of 2,585 bbl of oil and 3.691 MMcf of gas. Loomer TFHU tested 2,802 bbl of oil and 4.538 MMcf of gas.
The Loomer pad is in McKenzie County, N.D., and all three wells were drilled in December 2015. Proppant averaged 8.9 million pounds per well, Volker said.
“So, how’s it done? We’re super-fracking these wells,” he said.
Perforations in these two-section laterals are totalling about 1,680. “That’s 40 stages with an average of about 42 perforations per stage,” Volker said.
Sand averages 5,357 pounds per perforation, or about 900 pounds per lateral foot. Diverters are being pumped once or twice per stage, dividing the stages into two or three. “Thus, we’re getting great, homogenous frack jobs up and down the wellbore. That’s how it’s done,” he said.
Whiting has about 5,300 locations to drill in the basin, with about 4,800 of these in the core of the play. Of its 736,000 gross and 444,000 net Williston acres, 99% is HBP.
“We are well on our way to an over-1.5 million barrel EUR type curve,” Volker said. “We are very pleased with this. We think it is very indicative of what the industry can accomplish during tough times.
“You have more time to concentrate on being more efficient and getting the most bang for your buck. That certainly played out for us here with raising those EURs.”
These high-intensity completions in the basin are accomplished in seven to 10 days. Drill time has declined about 30% from 2014. Advancements in drillbits have reduced heat, and advancements in mud-motor technology have provided more torque. “So we’ve been able to really reduce the drill times, and I believe that trend will continue into 2018 and beyond,” Volker said.
Among 17 wells Whiting completed between December 2015 and November 2016, first-90-day rates have averaged more than 1,200 boe/d—or about 20% more than the next-highest IP rate producer with at least 10 completions online for at least 90 days in that time frame.
“We’ve been able to raise both our 60-day and 90-day rates more than 80% since December of 2014,” Volker added.
Whiting acquired Williston-focused Kodiak Oil & Gas Corp. in early 2015 at the beginning of the downturn. The deal was a stock exchange rather than cash, but it included taking on Kodiak’s debt. Since March of 2016, Whiting has retired 42% of its total debt—about $1.6 billion of this for equity and the balance via cash from noncore asset sales.
Properties that were sold carried lease operating expenses (LOE) between $15/bbl and $20/bbl. “We’re concentrating now in just the Bakken and Niobrara [in Weld County, Colo.] where LOE is only about $8 a barrel,” he said.
Of its 119,000 boe/d of net production, 91% is from the Williston Basin. The balance is predominantly from its Redtail play (157,000 gross acres, 132,000 net) in the D-J Basin with wells landed in the Niobrara A, B and C and in the Codell.
There, it plans to complete 105 DUCs (drilled but uncompleted wells) this year and test 50 frack stages rather than 40, and with 8 million pounds of sand per 7,500-ft lateral vs. 4.5 million. At this rate, the 105 completions would pump more than 800 million pounds of sand.
Whiting Petroleum’s bank line of credit is $2.5 billion; about $450 million is drawn. Within its bank agreement, Volker said, Whiting’s senior debt-to-EBITDAX ratio will not be more than 3:1. Its total EBITDAX-to-consolidated cash interests ratio will be no less than 2.25:1. In the former measure, Whiting is at 0.72:1; in the latter, 4.2:1.
Under its bond covenants, its ratio of consolidated cash flow to fixed charges (interest expense) will be greater than 2:1. Whiting is at 3.35:1. “So, again, plenty of room there,” Volker said. Also, “our first bond maturity isn’t until 2019.”
The company expects to produce about 40 MMboe this year and spend $1.1 billion in capex, with about 96% of that devoted to drilling and completion: $580 million in the Williston Basin (five rigs); $420 million in the D-J Basin (one rig and 105 DUC completions).
More than 50% of its anticipated 2017 production is hedged with three-way collars between $34 and $60, and collars between $53 and $70.
“There may be some misinformation out there about current [oil] inventories,” Volker added. “I think there will be more opportunities to hedge beyond 2017. We’ve already begun on 2018 and we’ll be more than 50% hedged for 2018 by the end of 2017.”
This is one of the strongest indications that crude oil oversupply is here to stay. With huge U.S. onshore hydrocarbon reserves, continuously improving technology which significantly reduces a drilling time and costs as well as ever growing number of DUC coupled with promised deregulation and tax cuts, it is unlikely to foresee oil price recovery anytime soon.
Although, there might be something which can be done. If it is possible to eliminate hedging, the removed safety net could potentially lead to the decline of production. But this will be painful because a number of oil companies will go bankrupt.