Presentation by Steven L. Mueller, President and CEO of Southwestern Energy to Credit Suisse Energy Summit in Vail, Colorado, February 9, 2012.
Note: only Mueller's comments about the Brown Dense are transcribed below:
Now I want to get to the Brown Dense, and this is one of the ones we always get the questions on.
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. 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. {Note: 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. Yesterday 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 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 dollar 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 last 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. {Again, Mueller is 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, 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 fields, and the takeaway comes to the Gulf coast, not to Oklahoma, so we don’t have to worry about that part of it.
PERIOD OF NON-BROWN DENSE DISCUSSION NOT TRANSCRIBED
BACK TO BROWN DENSE DISCUSSION
Q & A Time
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 average. 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’re 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.
So, we’re comfortable now, when I talk about 7-1/2, 8 million dollar {wells}, that we can get in that range, that there’s not something strange about the drilling site. ‘Cause that’s the other side. You don’t want to have to drill 15 million dollar wells for a 350,000 barrels or 500,000 barrel type {unintelligible}.
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Thanks for the excerpt, Bill.
Skip, for a newbie such as myself can you explain in general terms why the recovery rate would only be 10% (as stated by Mueller)? Does that mean 90% of the oil in the Brown Dense play is non-recoverable?
Smoke, Mueller's comment regarding 10% recoverable seems to be based on the data generated in the Bakken and the Eagle Ford plays which are further advanced as to number of wells and months of production. The petro-physical characteristics of the Brown Dense are a subject best left to geologists and reservoir engineers. As a landman, it is above my pay grade.
But I always heard that land men are at the top of the pay grades???
bpm, you heard wrong. LOL!
bpm, those who've inked ORRI over the decades (in the right locations, of course) . . . do sometimes reap upscale income status; and even the children of such interstate travelers really cash in, too
I had to recheck the numbers I've read in the past, but there are 3 methods of Oil Recovery and each yields a percentage of total available oil from any given field. Following is what is commonly listed:
Primary Recovery produces 5% to 15% of oil in a field - Naturally self-pressured wells producing oil.
Secondary Recovery produces a total of 35% to 45% of oil (includes Primary) - Use of artificial lifts, flooding of the formation and pumps.
Tertiary Recovery produces another 5% to 15% of oil in the field - Heating of the oil in formation through steam, C02 Flooding and Microbial (Germies that break down thick oil making it viscous)
The reality is that a lot of oil is still underground, we just do not have the technology to economically recover what is there and get it out of the ground. I sold Natural Gas to a number of the companies in California that used the Steam method to extract heavy oil 200-1400 feet underground in one of the largest Oil fields in the US. Only reason I was exposed to this.
The only caveat I'd add to your recovery factors is that the secondary & tertiary percentages pertain only to conventional (oil) reservoirs. Those factors are yet to be determined for shale and other unconventional reservoirs. Due to the nature of the shale reservoir rocks, their secondary & tertiary recoveries will likely be much less than those of conventional reservoirs.
Typical shale primary reservoir recovery factors range from <5% to ~10%.
SG, 10% recovery is fairly reasonable for a low permeability oil play like the Brown Dense. Recovery rates in many conventional oil plays is only 25% to 30%.
Thanks for the info. After reading the comments by Mueller, I had a hard time wrapping my head around a 90% (give or take) non-recoverable rate. But after reading some of the posts in the thread, and literature elsewhere, I have a better understanding of the difficulties involved in this play and maybe those somewhat similiar to it (I'm still very much the novice though).
It is important to keep in mind that the technology is rapidly evolving at an astounding pace and nobody (including the people at SWN) has any any idea what that technology will look like even five years from now. When he said "10%" he meant 10% given today's technology, what some of us would call a "static" analysis. While it is great for an investor presentation, it simply isn't a realistic estimate over time.
Just as, 10 years ago, nobody would have envisioned 3 Billion bbls conceivably recoverable from this region, nobody today can envision twice that much ten years from now. But it is highly likely a much higher percentage than 10 will ultimately be recoverable.
This could be an extremely important consideration, if for no other reason, for tax planning purposes.
Smoke, like you I'm a novice at this. but I work in a library, and quite by accident came across a good book that explains things like why you can't get all the oil out of the rock, and what the different techniques used are. The book is Introduction to Oil and Gas Technology (3rd edition) edited by Francis A. Giuliano. It does a good job of explaining so much that gets discussed here, including how land is divided and leases are written, as well as the geology that traps the oil and the drilling and processing to get it out. And it is not too wordy doing it, all the jargon is explained. It is helping me visualize what's going on with this inheritance I've lucked into. It is worth reading, ask for it at your local library or bookstore. Probably local colleges like southern arkansas have it in their library, maybe in the bookstore as a textbook.
so much for the advertisement, but back to the point - in the book, yes, it says that you can only really get so much oil out of any rock. It only flows so fast and so far - and some are tighter than others. The early Smackover wells gushed because it was self-pressurized, and when that bled off, the early technology couldn't get the rest. Now fracking and acidification and steam techniques can free up some more - but it will never get every drop out of the sponge.
Shale drilling and lithium extraction are seemingly distinct activities, but there is a growing connection between the two as the world moves towards cleaner energy solutions. While shale drilling primarily targets…
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