Thank you for the detailed answer. Are you saying that an unconventional shale oil well and a unconventional shale gas well have the same life span and the same decline curve keeping things equal?
When I began my engineering career 30 years ago in SW Kansas, part of our District's territory included the Panhandle Oilfield in Texas. These wells were drilled in the 1920's-1940's and many were still producing in the early 1980's. I'd guess that some are still productive today. One of the formations was extremely sensitive to fresh water; so we would rotary drill to near the base of the formation above, then switch out to a cable tool rig to drill the oil zone using old school percussive drilling techniques
These wells were completed in conventional rock, were generally unstimulated, and were all producing on beam lift. The biggest problem in my recollection, was paraffin wax in the crude, rod/pump problems, fill in the bottoms of the wells, etc. that had to be addressed by the maintenance teams.
Most of these wells were <10 bbl/day producers, the better wells would pay the electric and other unit expenses; expenses of the poorer producers were carried by the better wells. I remember one well that was about 50 bpd that made a significant percentage of the field's gross production for us.
Yes, I would be interested in the study.
I found this out on the internet.
Analysis of shale gas decline curves indicates need for more drilling
G. Allen Brooks, Managing Director for PPHB, LP, provides an analysis of Texas shale gas wells showing decline curves may be even steeper than earlier predicted. His numbers demonstrate that the value of a Barnett Shale gas well is largely realized early on, with 70 percent of the value produced in the first five years of its life. This would indicate that with decreased drilling for natural gas nationwide over the last 18 months, we should expect to soon see a fall-off in production. The data set appears rather small to draw broad-based assumptions, but if Mr. Brooks is right, expect continuous high drilling and completion activity to sustain US gas production rates as shale becomes an increasing percentage of the natural gas pie.
As has been pointed out the decline curves observed for the un-conventional shale wells have tended to be quite steep.
The first year's check buys the Ferrari; the check from year five won't cover the insurance on the Ferrari.
The problem with decline curves is that (to be accurate) they need to be seen through the "rear view mirror".
The decline curve for every well will be different. Natural Gas is more mobile than oil. Differing oils with different API gravities/viscosities will have differing mobility. The gas/oil ratio (GOR) will determine whether there is an assist in moving the oil. The mobility of all will be a function of the exact lithology of the shale at that location as well as the efficacy of the particular frac in that particular well. A generic decline curve will not be a “one size fits all”; I would not go as far to say that it would be a “one size fits most”.
There is the distinct possibility that the well will be re-fraced at some indeterminate time in the future ... and unforeseen technological advances might rejuvenate the well in a surprising manner.
To further complicate, the decline curve (and its extrapolation) measures (and/or predicts) production; unknown future commodity prices will determine the value of that production.
The good news is that a decline curve tends to (sooner or later) flatten out; promising a long revenue stream.
Further good news is that you tend to get much of your windfall early on; if it does not go to your head, you can enjoy the wealth while saving/investing for the future in a manner that ameliorates the inherent nature of the decline curve. Do things right and one can “have their cake and eat it too”.
I think there are a few things that would impact the value of the well besides the decline curve.
Would be safe to say that one does not know how long or how much in total a specific well is going to produce with any degree of accuracy?
From what I have heard, your royalties will fluctuate around roughly a 6-7 year cycle. For example, an oil company sets up a pad and drills a leg in the given 640 or 1280 acre unit. The production numbers will start off high and eventually peter off until the production is not as economical for the oil company. At this point, which is roughly 6-7 years depending on location etc, the rig comes back to the pad and drills another leg in the production unit. In result, your royalties increase greatly due to the increase in gross production of the well. Then the cycle starts again and continues to repeat if all goes as planned. That being said, the other legs drilled in the unit will continue to produce for many years to come (possibly 50-80 years some say). The production numbers of the other legs will be much lower than the first 6-7 years of their existence but will likely remain steady. The total number of legs can vary depending on unit size but I believe they are spaced 1000ft apart (up to 6-8 legs per 640 acre unit). That is what our buddy from Antero Resources has hinted at for awhile now. Please correct me if I'm way off.
IMHO, you are generally correct except for a few items.
1. The additional legs may be drilled at any time. I believe it will be more a matter of E&P economics than anything else. i.e., if well #1 is a "gusher", they may add all possible legs quickly.
2. In Ohio, some units have been approved with legs spaced as close together as 250 ft.