An Inside Look: Hydraulic Fracturing Q & A with Oil and Gas Leaders

The hydraulic fracturing process of extracting oil and gas from the shales deep within the earth using pressurized water, sand and some chemicals has been under intense media scrutiny since the explosion of the gas shales in the Marcellus Shale. The media and environmentalists have done a fine job of twisting the facts well enough to create hysteria and confusion over what really happens underground during the process without hearing from the other side of the debate: the oil and gas industry.

I talked with a handful of clients the past two weeks to ask them questions that haven’t been addressed well in the public regarding the hydraulic fracturing debate. Their insights were passionate, knowledgeable and show just how important this process is to domestic production in America.

Hydraulic Fracturing questionsIt was hard to edit down the interviews because of how informative their responses were. I’ve decided to split the questions into a few posts so it’s more manageable to read and if I get the opportunity, will share a second round of responses from others in the industry next week.

A special thank you to the three men who allowed me to pick their brains and see their side of this debate. Enjoy!

About today’s participants:

Pete Clute, a geologist, runs Clute Oil Corporation in Colorado. With 40 years on the job, Pete’s laid hands on every job in the industry and been at more than 100 frac jobs.

Scott Talmage, from Northwood Energy in Ohio, has been working all facets in the industry, and has taken engineering courses in how to create and perform frac jobs. He’s also been on site for 40-50 frac jobs.

L.C. Cobb is the vice president of Keystone Gas Corporation, where he handles the land, legal and revenue disbursement. He was previously involved with the exploration side when he lived in Ohio as the vice president of the largest independent producer in the state before they sold out and he moved to Oklahoma to start his own petroleum consulting company in the 1970s. He’s been involved in hundreds of frac jobs.

In your opinion, what is the biggest concern/danger today with hydraulic fracturing?

A: Talmage – The potential to contaminate water tables

“The main issue that you hear going on and on and on is the potential for contaminating water tables and that I find in terms of the injection process to be a relatively crazy concern,” Talmage said. “It’s sort of like if you’ve prepared your well and done it legally, the right way, the chances of you invading a water zone with your fracture are slim to none. I mean in the last 50 years you can look up when that’s happened and count them on one hand, you know what I mean?  There really aren’t many good cases that I’ve ever seen of destroying water with fracturing.”

A: L. C. Cobb – The flowback water after a frac job and how it’s stored

“One of the concerns that the environmentalists have is this water that comes back out and it ends up on the surface,” Cobb said. “What they are more concerned with is, of it not being disposed of properly, and that it is allowed to be evaporated or have it sit in the pond and then leeches into the earth.”

He said all water that re-enters the ground has the earth as a great filter, but that he can see some of the concerns as a result of the surface containment of water since the earth is likely not able to filter all the harmful pollutants out.

Why is there all the hype now in the media with hydraulic fracturing when it has been around for 50-60 years?

A: Talmage – The rush in the Marcellus Shale and media coverage

“That’s a good question,” Talmage said. “I think that some of that has to do with simply the media coverage. It’s just that much easier to make a big deal out of things.

“A lot of the nature of these shale plays are leasing up thousands of acres seemingly overnight and huge amounts of money are being spent by multinational companies. That kind of exposure in a relatively condensed geographic area leaves people to kind of freak out, and rightfully so. They are trying to make sense of this technology that’s been around for a long time and a lot of them take issue with things they don’t fully understand and blow it out of proportion,” he said.

What must go wrong in the process for water to be contaminated?

A: Clute – Wellhead or casing failure

“Having wellhead or casing failure is the only way you’re going to have something happen with your groundwater or surface water,” Clute said. “As soon as something like that happens, you lose pressure and you shut down your frac job. You cease pumping.”

Clute also offered another suggestion that he said he’s seen happen in the Denver area recently.

“These oil bearing formations in the Appalachian Basin are very, very shallow and if somebody goes out and drills a water well and produces it, there is a good chance they are dewatering the formation and bringing in hydrocarbons – that’s what happened here in the Denver-Julesburg Basin in coalbed wells,” Clute said.

Explain the incentive for not wanting anything to happen to anyone’s water.

A: Clute – “When you go to that much expense, you want that frac to go exactly where it’s supposed to go. These horizontal wells, they’re doing 20 stage fracs and the last thing you want is a problem,” Clute said.

So a lot of money is spent running all the frac jobs. Depending on the location, horizontal wells can cost several millions of dollars from drilling to completion. If it doesn’t go exactly where you want it to go, you’ve not done your job right, he said.

“Everything is designed to get those hydrocarbons out of the ground as effectively and efficiently as possible. And pollution is the last thing that anybody wants to have happen because if you are polluting, you’re not efficient. It doesn’t work,” Clute said.

How much preparation goes into a frac job?

From working with service companies to learning the art yourself, research, equations, studying the variables and knowing your geological formation is essential before completing a frac job.

A: Talmage – Has taken engineering courses specifically to look at fracking application and how to design a frac job.

“I’ve taken some intense courses specifically meant to get to the nitty gritty of what goes on in a frac job,” Talmage said. “I handle a lot of the inside work at the desk to design the frac. With the different variables involved to get it right, it can get really complicated quickly.”

A: Cobb – Has mostly worked with service companies such as Halliburton for the well sites he’s been on that have been fractured.

“Halliburton has been doing this a long time and they know exactly what pressure you have to achieve to get the formation to actually break down, and how far to go before fracturing and what they’re going to use as a carrier to carry the proppant down,” Cobb said. “They always have a safety meeting and get all the guys together and discuss exactly what they were going to do and how it should go.”

How many people are involved in a frac job?

A: Cobb – Depending on the job it could be anywhere from 10 to 20 or more people.

“It would vary depending on how much fluid or horsepower you’ve got out there,” he said.

What are the legitimate concerns that people should have from your perspective? You know how it works and how it’s supposed to work, what’s legitimate and what’s hyped up?

A: Talmage – Surface treatment options for how flow back water is handled

“I think a legitimate concern would be our surface treatment options.  The larger frac jobs are done with surface pits and after the fracturing, there is flow back into those pits,” Talmage said. “So how we contain, treat, transport and dispose of that fluid properly, I think, to this point hasn’t been addressed very well in terms of policy and government intervention.

“Those sorts of questions are legitimate and obviously we need to create a series of standards and look at some real scientific investigation of what potential possibility for damage and accidents are and take whatever steps are necessary to prevent that,” he said.

In terms of what’s hyped up, the actual injection process itself should not be a problem, he said.

“You’re talking about having a separation of literally a mile to 2 miles down and all of that surface, by state mandates and common good practice, has been protected through cementing and steel. The likelihood of actually having a problem would come down to negligence or poor completion practice or an inspector missing something and not the process itself,” Talmage said.

Check out the rest of their answers on Monday and Tuesday!

Interested in sharing your experience? Send me an e-mail and let me know.

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