Testing on WPX Energy’s Delaware Basin multiwell battery in Loving County, Texas, in March 2017. (Source: Tom Fox/Hart Energy)
DALLAS—Permian Basin drillers have begun to standardize drilling and completion programs that maximize production while keeping costs reasonable, according to the CEO of Dallas-based Haas Engineering, a reserve evaluation firm.
“We’re not seeing as much experimentation now,” Thad Toups told attendees at a Petroleum Engineer’s Club of Dallas luncheon Jan. 11. While “proppant is a driver in recovery,” Toups added as one example, “3,000 pounds [per foot] in my eyes isn’t any better than 2,500 pounds. Unless there is some sort of price change, I think we’re going to be dealing with 2,500 pounds” as something of a Permian standard.
Likewise, programs seem to be moving toward consensus on lateral length, well spacing and other factors, he added, as experimentation during a decade of drilling the Permian Basin’s multiple unconventional shales has found diminishing returns with some combinations. Engineers have tried out various ideas to try and generate the highest internal rate of return (IRR) per well for the lowest drilling and completion costs.
Well variables can be enormous, he noted, and that makes cost and reserve projections difficult. Studying the results of completed wells can vary further as operators put wells on with open chokes, or choked back by various amounts. Further production and financial numbers can vary according to differing gas-oil ratios and prices for crude, NGL or gas, as well as when a completed well gets turned on.
“Delaying sales by six months can lower IRR by 10%,” Toups added.
He noted ethane prices, in particular, swung wildly last year, from 25 cents/gallon as the year began to double that at 50 cents in September. “Then Mont Belvieu closed” to additional production and prices dropped.
Likewise, growing associated gas production from the Delaware Basin, a Permian sub-basin, hit limited capacity at the Waha Hub and gas prices fell to zero.
The shale plays are viewed at homogenous but they can still vary widely, he said. The Delaware, for example, varies from “oil in the east to gas in the west and everything in between.” Pore spacing also varies.
Toups described an extensive study Haas Engineering did of EOG Resources Inc. (NYSE: EOG) wells in the Delaware Basin to gain a feel for consistency, based on what one major operator has learned works best. “That makes it easier to see what wells will be like” given more predictable plans developed by one operator.
Looking at the multitude of variables, Toups said it’s easy to understand why operators are beginning to move toward benchmarking program by return on revenue rather than proved reserves.
For 2019, Toups predicted the decline in drilling and completion costs that occurred last year will continue. He noted the Permian Basin may have 5,000 drilled but uncompleted wells “and we won’t see that number dwindle soon” as producers await new pipeline capacity out of the region.
Paul Hart can be reached at firstname.lastname@example.org.