Question on Well Production.

Just curious.  Assuming we are all lucky, secure good leases, and our land produces....how long do these deep wells produce?  Can we expect royalties for 5 years, 10?    I know there are many variables - but what is typical?

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Permalink Reply by Mike Flor on December 30, 2011 at 8:46am

Some wells have been known to produce 30 yrs or more.  The initial production or IP is the most productive..in the first 6 months to a year before the decline rate starts to kick in.

Permalink Reply by Joe on December 31, 2011 at 1:16am
I would think past history was we used it as we needed it makeing the life of the well an un known variable. Now then if they build plants to make Lng to ship to china and start sucking and shipping as fast as they can. After all that is the objective to fill there greedy little pockets as fast as they can. Then how long do you think a well will last? They don't make money if it's in the ground.
Permalink Reply by Jack Straw on December 31, 2011 at 10:38am

As Marcellus Shale accurately noted “It is way too early to answer your questions. I would hope the wells last a long time.” We are in the first half of the first inning of this ball game.

Pondering possible decline curves have been an exercise that has been going through my mind for some time. It is not only a mystery, but can be an exciting one for those who get a well.

Horizontal drilling in the Marcellus Shale only really began in 2008; so there is insufficient history to say anything definitive about well decline curves. Decline curves chart production versus time (typically charted in semi-logarithmic scale); not enough time has elapsed to flesh out the curve.

Also, O&G Operators are reluctant to release any more information that they are legally required to; and, what information they do release is often in a format that is difficult to incorporate into a month by month decline curve.

What does appear to be the case is that the decline curve is initially very steep, eventually flattening out.

The short article on the web site below provides a hypothetical decline curve:

http://www.sooga.org/studies/Marcellus%20Shale%20Decline%20Analysis... 

The well decline curve starts with a well producing (a generous) 5 mmcfpd (5 million cubic feet per day). 

At 3 months, production has declined to 2.5 mmcfpd (2.5 million cubic feet per day).

At 15 months, production has declined to 1 mmcfpd (1 million cubic feet per day).

At 36 months, production has declined to 500 mcfpd (500 thousand cubic feet per day).

At 52 months, production has declined to 400 mcfpd (400 thousand cubic feet per day).

 

Consulting the example decline curve:
At 3 months, production is at 50% of initial production.

At 15 months, production is only at 20% of initial production.

You can see that at around 4 years, the decline curve is beginning to flatten (at about 8% of initial production. 

A second site you might wish to consult:

http://www.api.org/policy/exploration/hydraulicfracturing/upload/AP...

How long the well will produce will be a function of how long the Operator can economically produce the well.

The Operator will likely continue to produce the well as long as there is positive cash flow. Late in the life of a well, the costs will primarily be maintenance of the well equipment and expenses of a well tender. It is possible that the wells will produce for 30 or more years; but, at ever declining rates (and royalties). 

Quite early in the history of the well the Operator will have been able to recover their sunk costs. That is the attraction of the Marcellus Shale horizontal wells; high initial production allows for rapid cost recovery and early profitability.

Only time can demonstrate how representative the example Decline Curves are.

The lesson that I take away from the potential decline curve is that one should not go out and buy a Ferrari based upon the first month’s royalty check.

That “Flush Gas” of the first few months will likely put a continual grin on your face; a grin that others less lucky will find most annoying.

However, the number of digits in the monthly check will likely quickly decline.

That is the bad news, the good news is that royalties will likely stabilize in a few years such that you can be assured of having the means to enjoy a comfortable life (free from any financial fears).

 

To again quote the sage advice of Marcellus Shale, “For now if you’re drawing royalities enjoy the money and try to save some and give some money to charity. You are truly blessed.”

 

Happy New Year

 

JS

Permalink Reply by gary smith on December 31, 2011 at 10:48am

good thread jack. as these drilling co's usually poke one well to hold production ,then move on, about the time you start getting a big reduction in your royalties, they'll be back to poke a couple more on the pad,and you get to start all over! yea!

2s72s0k9mm8gdPermalink Reply by 2s72s0k9mm8gd on December 31, 2011 at 11:02am

And if you have multiple plays beneath your feet that annoying grin will be repeated numerous times!

And your grandkids may be comfortable as well.

Permalink Reply by Jack Straw on December 31, 2011 at 11:43am

From this site:

http://www.clintoncountypa.com/resources/CCNGTF/pdfs/articles/5.24....

"The final ingredient in the Pennsylvania triple play is the upper Devonian shale. Generally, combinations of several thinner shale formations like the Genesseo/Burkett are lumped together when people discuss the upper Devonian shale(s). As an upper Devonian formation, these shale(s) are generally found just above the middle Devonian Marcellus. Similar to both the Marcellus and the Utica, the productivity of the upper Devonian shales will likely vary significantly across the state. To date only one company has reported drilling into the upper Devonian shale and the well has yet to report production results.

Until more exploration is completed on the triple shale play formations, especially Utica and the upper Devonian shale(s), many of the rumors will remain only rumors. There is clearly momentum building for new shale exploration in some areas, especially the Utica, but not all shale will have the same production potential across Pennsylvania, nor will development be evenly distributed across Pennsylvania. More opportunities appear to be forming on the horizon, but more geological data is definitely needed."

 

By specifying from the Top Burkett Shale, it would appear that Exxon are grabbing on to all the Black Organic Shales.

The small operator (Becky Energy) retaining  the tradition tight shallow sands.

 

All in my humble opinion.

One size fits most.

 

JS

 

 

Permalink Reply by farmgas on January 1, 2012 at 8:11am

Jack, isn`t it also a reality check that not all of one`s property or lease will be included in a unit?   I have seen "Well Locator Plat Maps" that show a unit`s shape which only includes an acre or two to maybe 30 to 60% or so, of a property or lease.  Additional units placed side by side will be needed to include everyone, i.e., 100%.   That`s a lot more drilling and most importantly, time?   I think there will be those of us who  might enjoy greater gas royalties sooner then others...!  What do you think?

Permalink Reply by Jim Litwinowicz on January 1, 2012 at 8:40am

Farmgas;  while it is true that additional units will be needed to fully include all the acreage of some landowners, the truth is that many can be HBP'd because a lot of leases do not have a Pugh Clause stating only that portion of a parcel included within a producing unit can be held by production. For many landowners, this means they may get royalties on only a few acres but all of their land will be tied up for many years until the driller decides to drill an additional unit adjacent to the original unit. And with gas prices so low and so much land that they have under lease and need to get into production, that may even be decades.

Permalink Reply by farmgas on January 1, 2012 at 9:06am

Jim,  your reply is a very clear reality for many of us.   Would you think that those of us whose leases are owned by O&G Companies that acquire them through purchase of existing leases, may be in a better position of seeing multiple side by side units then those new leases from previously unsigned property?  In other words,  old leases are already HBP and are more attractive and available for quicker development...An example would be the leases purchased by CNX Gas that were previously owned by Dominion Transmission.   I`m sure there are similar examples of other acquisitions, too.  You`re right about the Pugh Clause and it`s impact on this situation.

Permalink Reply by Finnbear on January 1, 2012 at 11:30am

I think just the opposite may be true. Acreage that is HBP has no urgency to develop and is a cheap "reserve". Acreage that was recently leased at higher prices for a fixed period of time has a greater sense of urgency to be developed to prohibit loss of that investment. Just my opinion.

Permalink Reply by farmgas on January 1, 2012 at 11:50am

That`s the point....acreage not HBP is only going to be developed to HBP.   Probably only a single well will be drilled to HBP and the rig moves on to the next lease, and  repeat the same process.  Established O&G Companies who don`t need to run around creating HBP leases can settle down and really develope an area.  Right?

Permalink Reply by Jim Litwinowicz on January 1, 2012 at 4:04pm

Afraid Finnbear is right, they have no motivation to develop parcels that are HBP'd. Unless they have no parcels that are leased but yet to be drilled and they have no intention of leasing more property. But almost all are actively leasing more land. And they will drill new leases first to get the into the secondary term and HBP them.

The only advantage a HBP'd parcel has is the infrastructure that is there.  But these pipelines that serve older wells are usually too small and cannot handle the higher pressures these new wells develop.  Having the right away in place is a small advantage but I don't think a lot.

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