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Southwestern Energy says Roberson oil well in production, thinks its Brown Dense leases have potential for 3 billion barrels - Magnolia Reporter - Magnolia, Arkansas News: Local Business

Southwestern Energy says Roberson oil well in production, thinks its Brown Dense leases have potential for 3 billion barrels

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Posted: Friday, February 10, 2012 3:37 am

The Roberson well north of Columbia County's Atlanta community officially went into oil production at noon Thursday, Southwestern Energy Company said.

President and CEO Steve Mueller announced the news during a presentation at the Credit Suisse Energy Summit in Vail, Colorado.

The widely anticipated news marks the completion of Southwestern Energy's first of about 10 test wells it plans to drill into the Lower Smackover Brown Dense, a geological formation beneath South Arkansas and North Louisiana, in a bid to find oil on 500,000 acres the company has leased for exploration.

Southwestern Energy is using horizontal drilling technology it has successfully employed to tap natural gas from the Fayetteville Shale in Arkansas, but which has never been used on a large scale in the Brown Dense.

More information about the Roberson well and the company's second Brown Dense project in Claiborne Parish is expected during a conference call with financial analysts later this month.

Here is a transcription of Mueller's remarks about Southwestern Energy projects in the Brown Dense (thanks, Bill Dailey, of the Brown Dense Report on Facebook).

In southern Arkansas, we've put together 500,000 acres. Total on New Ventures plays in the United States, we've got about a million total acres. (Editor's note: New Ventures is Southwestern Energy's internal division for exploration of the Brown Dense and other unconventional oil plays). I do want to mention the 500,000, before I start talking about the Brown Dense, that other 500,000 is across different plays. But, in 2012, we have two wells in our budget for something we haven't talked about yet. It's an oil play in the United States. And to drill two wells in the budget, we'll have to talk about it sometime this summer. So kinda look for that.

Also look forward to the Brown Dense. In the Brown Dense we drilled our first well where it's got that yellow tag on there. (Mueller is here referring to the Roberson well on a map.) Finished that well in late 2011. Finished fracking on it last week. We have 11 stage frack on it. (Wednesday) we ran a packer and tubing in the hole, and as of about 15 minutes ago, we're supposed to be in production. Now I haven't got the actual confirmation of the time of production, but we're supposed to go on noon Central Time today. So it is on production.

It will take several days to clean up. But, by our conference call, we should be able to talk about that well.

I get asked all the time, "What would make you excited from a production rate on that well?" What makes me excited and what economics are, are two different things.

If we could get a 100-barrel-a-day rate out of this well, I'd be jumping up and down. What you really need to have to make economics work on what we think will be an $8 million well, ultimately, is somewhat between 400 and 500 barrels a day.

"But we fracked this just like a Fayetteville Shale well. Four hundred feet between the fracks. Very similar design. We did not - it's about a 3,500 foot total interval -- we didn't space them real close together like they do in the Bakken, we didn't do some of the things they do in the Eagle Ford. So if we can get any kind of decent rate out of that, I know we can work it up to that 400 to 500 barrels a day. So that's what would make me excited as we go through.

We've also been working on the second well that's just across the border in Louisiana. That well reached total depth (Wednesday) night. It's got a total of a 6,700-foot lateral on it. We'll be running casing on it the next couple of days. And assuming we can get casing all the way to bottom, we'll have almost double the lateral length we do of the first well. We'll do roughly the same amount of spacing, but this will give us a test on what happens if you have a longer lateral with roughly the same amount of spacing between our fracks.

And then there's some other wells posted on there. (Mueller is again referring to a map.) "OBO" is "operated by others." The well closest to us -- our two yellow spots -- the well operated by Cabot, that well is at TD (total depth), and is actually fracking right now, so you're getting some information on it.

There's two stars in that big red blog on the right hand of the map.

That's the Monroe Gas Field. The southernmost star is a well operated by Devon. I think they've actually fracked that well and should be flowing that back.

The star just north of that is a well that's permitted. It has not spud yet.

And the far right hand star just barely on the edge of that map, that is Exxon XTO well. They're at TD on that. So in the next 30 days you should start seeing them frack that well also.

The end result here is that when we went into this play, and announced it last summer, we thought we were going to have to drill 10 wells, it would take us up through the first quarter of 2013 to drill all 10 wells ourselves, and somewhere in early 2013 to figure out if this works. With the industry helping us, I can't guarantee it, but I think by end of summer, we'll have figured out if this works. As an industry, we'll have 10 wells. And certainly by the end of the first quarter we're going to have information on at least five wells, and may be even six wells at that point in time. So this play in developing rapidly. We're excited about this.

People say, "What could be the potential here?" On our 500,000 acres, again, with just a little bit of core data, and a couple of vertical wells to help us figure this out, we think we have about 30 billion barrels in place, and you got 10 percent recovery factor, we have the potential of about 3 billion barrels of oil. So this could be significant to the industry.

There is a takeaway, both on the gas and oil here, because there's a conventional gas and oil field, and the takeaway comes to the Gulf Coast, not to Oklahoma, so we don't have to worry about that part of it.

(Editor's Note: A question and answer time followed and many of those were directed toward the Brown Dense.)

Questioner: Steve, in terms of the Brown Dense, were you talking about an IP rate of 100 barrels, or were you looking for a 30-day rate?

Mueller: That'd be a 30-day rate. When I talked about 400 to 500 barrels a day, that was a 30-day rate, not an IP rate.

Questioner: What do you think the oil in place is in the Brown Dense? What kind of recovery factor were you assuming? And what's the biggest risk to this not working?

Mueller: Yeah. The oil in place, as best we can tell, is right around 30 billion barrels in our acerage. Most of these oil plays -- again, we have no real production so you assume like a Bakken or an Eagle Ford, they're talking about 9 to 10 percent recovery package in whatever they have. So you talk about 2.9, 2.8 billion barrels of potential recovery.

What's the most critical factor? We've eliminated some of them. We went in with four or five issues.

One issue we went in with was there's a wet zone about 400 feet above where we've planting our laterals. Would you, when you fracked, somehow get into that wet zone and, if you did, you'd water out, and it wouldn't really matter how much oil you'd have ‘cause that water would overpower.

We tested, when I say we did 11 stage fracks, on the first well we actually did three stages, produced it for 10 days to make sure that we hadn't fracked up into the wet zone. We did not. So we eliminated that one.

The other eight stages of frack acted like the first ones. So I think we're in good shape that direction.

Now the other big critical thing is, or the second biggest critical thing was, is the rock brittle enough. Can you frack the rock without having to use too much horsepower and all those other things?

It fracked exactly like we thought it was going to frack with the horsepower we thought we needed. So it looks like it's brittle enough and will frack the way you want it to do.

The third thing is, how tight is it? Ultimately, what's the natural fracture system? And how much oil can you really get out of it? That's what we're going to figure out in the first four wells or five wells in the production part of it.

It could be that there's very little natural fracturing. It's got about a 12 percent porosity, kind of an innate porosity in the rock. And it's got about a 0.1 millidarcy. If it doesn't have some natural fracturing, then you're going to have to use more energy, more fracks to make it work. And we're going to have to figure that out as we develop this next stage.

So the most critical thing we have to worry about is just how tight is the rock, how much natural fracturing there is. And you really can't tell that from cores. The only way you can tell that is from production.

The other thing I can tell you early on was can you drill the well economically.

In the first well, the lateral drilled very, very slow. It took us, to drill that 3,500 foot lateral, it took us over 30 days, 40 days, closer to 40 days to drill that lateral. To drill the 6,700 foot lateral on the second well, we did that in about 22, 23 days in that well. We took some learnings from the first one and applied it to the second, and it worked.

 

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