FORT WORTH, Texas—The Spraberry and Wolfcamp formations have made the Midland Basin a popular play. However, many operators are tasked with determining how close is too close when it comes to well spacing.

“I’m going to talk about something that most CEOs probably don’t want to talk about, and that is why I think the wells we are drilling in the Wolfcamp and the Spraberry out in the Midland Basin ultimately will probably average a little bit less per well than what people are saying they are right now,” said Steve Gray, CEO and director of RSP Permian (RSPP), at Hart Energy’s DUG Permian conference on May 20.

Gray said there are massive oil-in-place resources in the Midland Basin. “If you look at a type log in the middle of the basin, you can see in addition to the five zones that we’ve been producing there are probably four or five others that have potential and have been tested by other operators or are carried in the inventory of other companies. You’ve got a total section that’s probably 3,000 feet or 4,000 feet thick [that’s pay], and when you compare that to other resource plays in the United States, it just dwarfs most of those other plays,” he said.

RSP Permian has spent the last couple of years going through the delineation mode. The company tested different intervals and delineated the boundaries of the play and worked on cost-curve, getting well costs down and trying different completion technologies. Now, the company is moving into the development mode of the basin, and that was the focus of Gray’s discussion.

“It’s a complex sort of three-dimensional game of chess deciding how to develop these reservoirs,” he said, regarding the development phase of the Midland Basin.

Gray said he is constantly asked two questions: First, what’s the company’s type curve, what are the reservoirs on the wells RSP is drilling and what is the ultimate recovery expected from them; and secondly, how close together can the wells be drilled? He reviewed the process RSP has followed.

“The first thing we did is we used log core data to try to come up with what we think the oil in place is, how big the target is, and then obviously the next step was to go drill the delineation wells and figure out what the wells are capable of making [and] work on the completion technology,” he said.

While the company was completing the wells, it completed some microseismic surveys to see if it could come up with an idea of how big an area it was draining with the wells. Then the company did some spacing pilots and put some wells in side by side to see how they communicate with each other and how they react.

“[We wanted to] see if we can come up with what we believe is the most efficient way to develop the reservoir, and when I say most efficient what I’m talking about is how do I maximize the net present value of this particular lease or this block. I’m not so much interested in how much oil each individual well is going to make as I am [with] how do I get the maximum value out of the resource,” he said.

Spacing pilots in low permeability reservoirs will take a long time to resolve, Gray said.
Currently, RSP is trying to determine how wells are going to produce if the wells are drilled closer together. “This is what nobody wants to talk about,” Gray said. “[But] this is what we all want to figure out in this industry.”

Hypothetically, if an operator drills wells 2,500 feet apart, the subsequent wells are going to make 100% of what the original well did, he said. If the operator starts drilling wells closer together, like 1,000 feet apart, then the subsequent wells are going to make 80% of what the original well did. Then as the wells are drilled closer together, they’re going to make subsequently less, Gray said.

“Once you get less than 500 feet apart, you really start to see a lot of communication, and so your ultimate recovery is going to be less. But that’s OK with me because if I drill them 2,500 feet apart and they only make a million barrels, that’s great. But I’m leaving a resource in the ground that’s not being developed,” Gray continued.” So what I’m going to figure out is the optimum spacing where there’s some communication so I know I’m not leaving anything behind.”

Furthermore, in another example, Gray said if an operator drills four wells across a section that is going to make 900 thousand barrels of oil equivalent (Mboe), the operator is only going to recover 2% of the oil in place. If the operator sets five wells at 3 million barrels (MMbbl) across a section, the operator is going to get something like 2.5% of the oil in place. If an operator goes from five wells to 15 wells across a section, the operator won’t go from 3 MMbbl to 9 MMbbl; instead, the operator will go from 3 MMbbl to perhaps 7 MMbbl “because each subsequent well means you’re going to get a little less per well,” he said.

“But at the end of the day, we’re still arguing about less than 10% of the oil in place, so I think with changes in technology and completion design, maybe that whole equation changes,” Gray continued. “I’d love if I could tell you guys I’m drilling million-barrel wells, but my guess is when we all go to full-scale development, million-barrel wells are going to be rare. That’s OK with me because I’d rather drill more 800,000-barrel wells than a few million-barrel wells.”

RSP is focused on spacing wells to maximize net present value, not production per well, and the EUR of its wells will be a function of that spacing, Gray concluded.

Contact the author, Ariana Benavidez, at abenavidez@hartenergy.com.