Darrel Koo: “…There isn’t a lot of transparency.”

Getting information about new Permian Basin wells has been complicated for both royalty-interest owners as well as for accomplished analysts. “The data-quality issues are certainly a concern in Texas,” Darrel Koo, senior associate, energy research, for ITG Inc., said in a DUG Permian Basin 2014 post-presentation Q&A session in Fort Worth in May.

“The biggest issue for me (is that) production in Texas is allocated to the lease level for oil wells. There may be 50 oil wells producing and Texas doesn’t tell you how much production is associated with each well. It’s difficult for an analyst to get type curves.”

One attendee said he is receiving royalty checks for wells that have been online for as many as nine months but there is no reported production. Koo said, “There are games that can be played. They don’t release those reports until after the wells have been producing for a long time…I can’t speak to when that will be resolved—if at all—but we certainly think it is an issue for people trying to analyze this (Permian) play.”

Determining water cut has been challenging as well, he added. “In Texas, unfortunately, the water-production data is not great. Operators are not obligated to report water-production data, so there isn’t a lot of transparency.” Water is indicated in completion reports, but “there is a lot of load water in that. You can’t say the formation is producing 70% water. That’s just not the case.”

The water cut is lower, however, than, for example, that which is produced from the Mississippi Lime play in Oklahoma, he added. There, he estimates water-disposal and other lease-operating expense is $10 to $11 per barrel. “In the Midland Basin, Concho (Resources Inc.) is operating at $6, $7, $8 on the average. Water is not materially affecting LOEs (there).”

For anecdotal reference, in the Delaware Basin, “we do have information from New Mexico on water-production data and some of the Wolfcamp wells there are 20% water cut, so it’s not that bad in our opinion.”

Benjamin Shattuck, upstream analyst, Lower 48, for Wood Mackenzie, said he doesn’t see a water-cut issue in the Midland Basin either but he expects water-sourcing to become a widespread problem. “Disposal has been problematic also.” Trucking it out is some $3 a barrel.

“You can do the math on that and see the value destruction pretty quickly, if you are putting in an SWD (saltwater-disposal well) per section at 25 or 50 cents per barrel. You begin to see a $1- to $1.5-million-per-well swing there.”

Raphael Hudson, director, upstream research, for Hart Energy, noted that operators are looking at recycling fracture-fluid water, using produced water and/or sourcing brackish water from San Juan Basin wells. “We believe there are ways around it, but there certainly is a problem. It is a constraint that needs to be addressed.”

Bob Manelis, general manager, Permian production unit, for BHP Billiton Ltd., said, in a separate Q&A session, that the company’s current Permian fracture-fluid recipe is 70% freshwater and 30% produced water. The company plans to eventually use 100% produced water.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.