Jordan Blum, editorial director, Hart Energy: I'm Jordan Blum, the editorial director at Hart Energy. We're here at SUPER DUG in Fort Worth. I'm joined by Mark Pearson, the CEO of Liberty Resources. We're talking about enhanced oil recovery in the Bakken. This is a process you all started almost five years ago. I guess with a—what do you call it, a gas-rich huff and puff program? Can you take me through the timeline and where we are now?

Mark Pearson, CEO, Liberty Resources: Sure. In our primary production of our wells in unconventional fields, we're typically only recovering 10% to 15% of the oil in place. And so that's just a lot of resource that's being left behind. So we've been studying this for several years now. What can we do and go about learning in the field as well as in the laboratory and running reservoir simulation? So we've actually conducted two phases of field tests with different types of just a gas injection and then a water and gas injection. And our last test, which was our phase two first stage project was admissible gas, which is, so it's basically our Bakken-produced gas, which is 70% methane, 20% ethane, 10% propane. Just taking that, re-injecting it in pressure and alternating it with produced water or fresh water with a surfactant to basically go in and just mobilize oil that's left in place to increase the productivity coming out of the wells. And after a year and a half of production, we've averaged about a 25% increase over the past year, just in that one well, and in an offset well, a 20% increase in that offset well, so pretty encouraging first steps, and we're gonna be doing a second phase test, or the second part of our phase two test this Summer.

JB: Very good. And it's basically cheaper and more efficient to use the produced gas at the source?

MP: Right. We're not having to buy CO2. We're not having to pipe that line in. We're not having to change out our tubulars or anything for corrosion issues. We're not having to separate out CO2 from the sales gas immediately when that well turns round back on production, we're able to sell all the oil, all the gas, because it's the produced gas that was re-injected as part of the miscibility process. So, very cost effective way to go about increasing recovery and something which could be 15 to 25% boost in recovery for our wells, so something that's very exciting. And we're also excited that other operators are catching on as three of the larger operators in the Bakken that are all planning their first EOR projects this year, and I think it's something that we're gonna see a lot more of in our industry.

JB: Does it factor in much with natural gas prices being lower now?

MP: Yeah, well, it certainly helps because when we look at the full cost of it, we actually purchase the produced gas. It's coming off a pipeline, so we've gotta pay the producers or the owners of the wells that it came from. So in terms of a cost standpoint, the last pilot we've averaged, we think about a 3.6 Mcf per barrel of oil. So obviously if we're having to pay $2, $3 an M versus $8 or $10, there's a significant difference in the cost-benefit equation.

JB: Very good. And can you elaborate too, on just how all this plays into like you were talking about the Bakken activity kind of moving north of the core, so to speak?

MP: Well, anything you can do to increase productivity with time. So, whether it's from drilling along the laterals I talked about in my talk, moving a big chunk of our program to three mile laterals, that's something that the North Dakota Industrial Commission is really behind. [It] sees the potential for maybe 15,000 three mile lateral wells in the Bakken. And so basically, we're moving from what was the traditional core of the Bakken to what we call the Northern Extension Core. Basically it's in the same depot center of the basin, but it's just a little bit lower pressure, a little bit lower, a little bit higher water cut, but by running longer laterals, intense completions. And if we can add some added recovery from EOR, it makes performance as good, if not better than traditional core wells.

JB: Mostly about being more creative and technologically savvy as we get out of the core.

MP: Absolutely. It's that we're all learning as an industry, we're learning as we go, and learning to be more efficient, learning to get more out of the ground than what comes out on the initial first gush.

JB: So this makes you pretty bullish for the long term?

MP: Well, I think it just talks about how technological our industry is and that it's not just a matter of sticking a hole in the ground and suddenly oil comes out, which is what my father, who was a refrigeration engineer assumed it was and couldn't understand what all this completion technology was about. But it really is the application of technology, which is what petroleum engineering is to the subsurface. And we're recovering more hydrocarbons out. We've gone into unconventionals in the last 15, 20 years in a much greater way, and now we're finding out how to get more of that unconventional oil out of the ground.

JB: Great. No, thanks so much for joining us here at SUPER DUG in Fort Worth. Yeah. For more information, please read and watch online at hartenergy.com.

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