Sorry for any false hopes. I will not post anymore unconfirmed rumors.
Les B, I concur that there is insufficient information that's why I mentioned unknowable EUR. Big, the industry will not support a horizontal play with well payout anywhere close to 2 years. Or 1 year for that matter. The well costs are likely well north of $12M now (I'd love to see an AFE as it could easily be north of $16M) but based on the wells drilled to date should ultimately be close to the cost of a Haynesville Shale horizontal. The play is too deep to get to $7M or $8M per well, $9M might be possible, but that could take a couple of years. For SWN it is attempt number two but for experienced horizontal drillers in the play it is number five. I personally think that SWN will get to a point of economic success with a few more wells. And that they will get better at both drilling and completing. My take away from the announcement is that the rate of development will continue to increase.
Skip, no one, including myself, can make definitive statements about what is acceptable to "industry" regarding investment payouts. There are multiple economic indicators (ROR, PIR, PVR, NPV, etc) with payout being only one. Each company has their own criteria depending on the nature of the investment including risk, size of investment and revenue life. It is not uncommon for investments to have payouts well beyond two years. I have spent some time in my past evaluating such potential investments.
The bottom line is future wells producing 301 BPD and 1.7 MMcfd could be economic in this play.
Point taken. I sometimes get tired of continually including IMO as I think that it is a given that the vast majority of site comments are the members' opinion. What would you project the well cost to be for an economic well with a 301 BOPD max 24 hour flow rate over the first 48 days of production given some unknown but acceptable EUR?
Skip, your comments carry a lot of weight on GHS due to your experience and credibility.
For a reasonable decline rate (50% 1st yr) the economics would support a well cost > $15MM. The estimated EUR would be ~ 343 MBO.
For a more severe decline rate (75% 1st yr) the economics would support a well cost up to about $10MM. The estimated EUR would be ~ 152 MBO.
What is interesting is that they are dramatically reducing the distance between perforation sets from 344 to 133 feet. (19 stages in the Garrett that has a 6,536' lateral vs. the planned 30 stages in the BLM 4,000 ft lateral). They are going to make a sand pile around the wellbore. More sand pumped per cubic ft of resevoir rock=more $/per well, so it has to work significantly better - and it can.
Does anyone know if SWN is using micro-siesmic when they are fracing?
Jim, I found that detail of interest also. I was hoping for a comment about the drilling challenges to date and how SWN was adjusting to address them. I believe there have been prior mentions of micro-seismic although I do not recall if they were associated with the Garrett well.
Jim, Steve Mueller said this morning in response to an analyst's question that they did not micro-siesmic Garrett. They did Roberson, however.
Mueller said in the call this morning that they did not use micro-seismic monitoring for the Garret well so they are unsure how far the fractures extend.
Another thing he said which I found interesting is that they didn't use acid in either the Roberson or Garrett well frac jobs. I had thought that acid was always used for carbonate reservoirs and I think Cabot used it for their Denny well. Mueller did say that they are now testing the effect of acid on one frac stage in the Roberson well, the stage nearest the vertical bore.
I thought that interesting, too, obed. BTW, my streaming audio worked fine this morning. Don't have a clue what happened earlier, but thanks for your suggestions.
Jim, all LSBD tests so far have been updip of the regional Smackover fault system, with the new N. Mt. Olive location the furthest downdip to date. IIRC the Mt. Olive Field itself, a few miles south, is a Smk 'A' strat. trap on the upthrown side of the first regional fault. So that test will be getting fairly close to a major structural boundary.
The scattered reports so far indicate the L. Smack., as expected, is very tight, difficult to drill laterally and hard to frac successfully. I'm no expert in fracing science and technology but it seems to me that better results might be found near and within fault zones, where natural fractures are more common. Downdip means deeper, more expensive, and likely at the margins of the oil window but still in a liquids rich environment. I realize that conventional wisdom says you don't want to frac into fault planes and bring in formation water from above or below, but many of these planes are sealed and the natural fractures occurring around them would certainly enhance the productivity of artificial stimulation. Just sayin'
Getting better... still needs to go up a lot to work. I'll be real curious to see the decline curve.
Me too Chester.
Letas keep in mind that the vertical BD wells have quickly petered out in very short time. 300 bbls/d dounds great, but if they don't hold up its not going to work.