Would appreciate comments from the Forum on Math & Cost associated with the drilling of Haynesville wells at current prices.
With well cost averaging $10M and current spot market gas prices fixed at $2.09 (reaching lower every day & with no end in sight), why would companies be drilling alternate unit wells in this enviornment? Encana's $5 hedging disappears at the end of this year; CHK has no gas hedged & I'm guessing EXCO, Shell, BHP, etc.'s position can't be much better. For the benefit of discussion, let's say $4 hedge price is engaged - the average Haynesville well of 3 - 4 BCF, after royalty is paid, makes little or no profit for the operators.
John, average well cost is lower than $10 million with some operators having dropped capital costs down to the $7-8 million range. The average Haynesville Shale well has an EUR above 5 Bcf with the typical alternate wells curretly being drilled having EUR's above 7 Bcf.
I am not sure what you mean by spot market gas prices but daily NYMEX quotes and daily cash natural gas prices have little bearing on current well economics. Hedged gas prices for 2012 still support some drilling in the Haynesville Shale but this activity will continue to decline if NYMEX futures prices do not improve.
I've been watching very closely since 2008 and have yet to see many wells above the 3 BCF mark with race exceptional wells producing 4 BCF (with little left in the tank). Would you kindly point out the wells that have produced 5 BCF or 7 BCF?
John, you have a very good understanding of what is going on. Using decline analysis, someone can come up with just about any EUR they want by adjusting the "b" in the Arps equation and terminal decline rate. But if you consider only economically significant production, there should be many, many wells, by this time, with cumulatives above 7 BCF if an average of 4 BCF is to be achieved. To answer your original question, operators likely believe the economically significant recovery will be higher than 4 BCF per well on the alternate wells. Whether they are right is a grand debate. I'm sure they tend to infill the better units.
John, take a look at Serial # 238488, the Sample 32. It produced 4.3 bcf in 12 months and has produced 7.68 Bcf in 30 months. Is still making over 100 million/month.
That's what everyone is aspiring to for sure and hopefully we'll have a really hot summer and very cold winter. That would be a great start to alleviating some of the hurt put on gas prices!
LOL for the Day.
One of the problems that I have to keep in mind is that data available to me is not very good. The state, and therefore IHS show this well with a cumulative of 4.2 BCF and currently producing 46 mmcf/month. Early production, not reported under the unit LUW, is hard to run down if working with 1600 wells. SONRIS shows 238488 associated with 615551, which is reported to have made 46483 MCF in March. If, in fact, it made over 100,000 MCF then my opinion on EUR is suspect.
I have located over 600 wells that appear to have an economically significant EUR of less than 3 BCF, but that is based on IHS data.
As others point out - the ultimate recovery will be determined by the actual long term decline rates. While the initial blitz of production and very rapid initial production decline garners all of the attention, I have always found the latter part of the predicted decline curves to be pretty interesting. I suspect that there is a natural tendency to think of the decline curve as staying as steep as it is in the beginning. Although 1/3 and 1/2 of EUR are predicted in 1 and 3-4 yrs respectively, the rest of the EUR is predicted over 20 - 40 years or more. While how wisely the initial windfall is used probably varies widely, I tend to think positively about the latter part of the HS predicted flattening decline curve as something like an annuity - if the predictions hold with some accuracy... (and who knows what NG prices will be)
LesB-- please explain what a typical alternate well is vs a haynesville shale well, Thanks for reply answer
Adubu, alternate (Haynesville Shale) wells are the ones drilled in a Haynesville Unit in Louisiana after the initial well is drilled in the unit. Most of the current Haynesville Shale wells currently being drilled in Louisiana are alternate unit wells.
LesB-- Why IYO (In your Opinion)with NG at $2.5 or< would operator drill addition alternate wells in Unit after one well HBP the leases? Are there leases with drilling clauses with that short of time between wells that force operator to drill out the unit?
Adubu, many companies have their 2012 (and some 2013) natural gas production hedged at $4.00+ per MMBtu resulting in profitable drilling in the Haynesville Shale. Companies still need to generate earnings growth so it is just a matter of where the Haynesville Shale wells rank in their overall development opportunities.