The discussion on UNIT SIZE is interesting. I think it worth mentioning that the reason the Lessee-Producer requests larger units is:
He wants to hold more property longer without drilling. The leases are extended for every lease within the unit and any property extending into the unit. Do not expect aggressive drilling and royalties where unit sizes are increased over the maybe 400 acres practical for a unit. Expect the opposite - drilling 1 or 2 wells in the unit to hold the leases and hold the rest of the unit-leasehold area as reserves for the future - problably the distant future. Consider requiring a minimum annual minimum royalty after a few years in exchange for the enlarged unit.
640 acres just happens to be one square mile. It has nothing to do with the practical operational size of a unit.
I would like to comment on some statements regarding the lateral distance that natural gas could possibly travel from a fraced horizontal well bore.
When you start out in Geophysics, equations assume that you are in a homogeneous isotropic Earth. What does homogeneous isotropic mean? It essentially means that the Earth’s physical properties do not vary in any direction.
The Earth is anything but homogeneous and/or isotropic – reality quickly rears its ugly head. Thank goodness for the advent of super computers, they prevented the science from grinding to a halt.
Since we have to live with (and in) a inhomogeneous and anisotropic world, it is difficult to either predict or quantify how far natural gas could possibly travel from a particular fraced horizontal well bore. That horizontal distance could be several hundred feet or (infrequently) could be several thousand feet.
To further complicate, the amount of gas that would drain (as a function of horizontal distance from the well bore) is not likely to be a simple linear relationship. It may not be “rocket science”, but the mathematics is just about as ugly.
Dr. Terry Engelder (Pennsylvania State University) is the most recognized expert on the Geology of the Marcellus Shale.
Below, I copy page 13 from Dr. Engelder’s following source:
Fractures opened by hydraulic pressure generally
drain a swath of a production unit about 300-500
feet either side of a well
– This is a common drainage distance even under unleased land
Rock splitting by hydraulic pressure is known to
travel as much as 2000 feet from a horizontal well
– Some gas may come from distances up to 2000 feet although
the volumes from this distance are very low.”
All in my (and Dr. Engelder’s) humble opinion,
One size does not fit most,
The example I showed of the Way North unit shows the horizontal well bore within 100 feet of land that is not leased on one side and about 100 feet from the edge of the unit on the other side. With the lowest setback of 330 feet used by the 34 states out of 50 which have this law, this situation would not be permitted. It is unfair to the landowners adjacent but not in the unit and to the landowner who is not leased.
It has been more than 50 years since any gas company has operated in a state dumb enough to let them do so without any rules about units and setbacks and they still can't believe it is happening in arguably the biggest shale gas play in the world. If you talk to the gas companies they will haul out their maps with existing and planned well pads. The units on these maps are perfect rectangles with appropriate setbacks and 600 to 700 acres per unit which seamlessly cover hundreds of square miles. Think about who benefits most from an optimal grid of well pads - the gas company.
Enforcing setbacks and property maps is not rocket science - county planning commissions do it every day. Believe me, I would love to demand that DEP do their job and enforce the Conservation Law, The fact that the industry doesn't like the existing law is because it will force them to treat landowners fairly.
If 34 other states have figured out how to apply spacing and setback laws, I am sure Pennsylvania can too. I have included a .pdf file of a presentation on this subject to the Governors Marcellus Shale Commission by Dr. Engelder who was also a member of of the Commission.
Hi John, Thanks for this post!! The 285E unit that is part of Dr. Engelder's presentation is the unit that we are in, I was wondering why the 1026 well was not producing/drilled now I know why...
I will be contacting Anadarko and seeing if they intend to go around the holdout or not drill the well at all...
Thanks again for the info!!
Ok, I made contact with one of the people that I got to know at Anadarko who told me this situation was resolved the unit was reconfigued and the well drilled after numerous efforts were made to resolve the issue with the person holding out with the 22 acres.
In my opinion Anadarko is a good company to deal with and they were fair in lease negotiations with us and I believe my representative when she said they offered this hold out everything possible but they were that opposed to drilling of any kind that they would not budge...
In turn through the actions of the holdout some neighboring properties that were originally included were then excluded after the reconfiguration, which is not fair because it now precludes them from having their resources developed to their fullest potential..
Thank you John,, well said also. Perhaps this is the root of the problem....yes, it isn't perhaps...it is the root of the problem. If there had been certain guidelines already discussed and enacted legislation then it wouldn't leave the landowner trying to figure out what unit size they speak of in the clauses or what set-back they could possibly need.
Now we have a variety of assortments of units, setbacks, and even whether the pipeline is in when they install a well. I mean if you think about it...if there were rules that could include that a well couldn't be installed until a route of pipeline access was determined...then when people would lease they would know that a company couldn't just plop a drill site with a well and sit it there for ten years using the excuse there is no pipeline. It has been over 7 years that Chief knew that the county that I have land in needed pipelines...and they have had wells there since 2010 and earlier.....so one vertical well is holding a more than 1000 acre unit? with no idea when pipelines will ever be in? perhaps a new clause needs to be done on the leases requiring that pipelines have to be installed for transport with the well before the company can use an extension of the primary term. For many of the folks, including myself, would benefit at the rates being paid on leases today...rather than still using the low figures of 2005 -2009 with no royalties yet....with no guarantee if the investors of those companies in the areas waiting for pipelines will even return to work those counties that soon. Yeah, there should have been a clause for only extending if there was also a requirement with a specified time of the installation of the pipeline system, so that they couldn't just spend money on a well pad (though that cost money) and sit on it while they took the investment money of the flip to another county to do the same thing or to actually produce..
Sam, Jack, and others here. thank you both for your recent post of info.
I am finding that there are sooo many versions of how large a unit is, how far the drilling horiz. goes, etc.
so I went looking for what Pa. law states...and haven't found that info exactly. I did find some interesting info at this site (no date on it) and I see that he mentions what seems like a requirement of having ten horiz. wells at that pad...now I know of at least one large oil company in Pa. is holding land acreage of many lessors with only one well vertical and one horiz. well "not installed yet" as a 1120 unit and recorded? can this be legal? do you know where I can find such info?
an exerpt from Rep. Garth Everett's fine page at that link:
"First, virtually all Marcellus gas leases allow the pooling or unitization (combining) of two or more leased tracts together into one “production unit.” These units are necessary as a result of advances in both horizontal drilling and hydro-fracturing technology. It is my understanding that currently up to 500 acres of land can be developed from a single five-acre drill pad assuming that 10 horizontal wells are drilled from the pad. That means that a 1,000 acre unit can be almost fully developed from only two drill pads. Not only is the development of fewer drilling sites economical for the gas developer, it means that with fewer sites there will be fewer pipelines and a drastically reduced impact on the landscape and environment.
Many older or early leases specify production units of 640 acres, which happens to equate to one square mile which was a very common-sized unit in other gas producing states like Texas and Oklahoma prior to the development of advanced horizontal drilling techniques. Some leases in Pennsylvania simply allow for unitization and do not specify a minimum or maximum size for a unit."
Now I am discovering that the unit that my land is in is soooooo far away from the well pad and there is only one well vertical and one well not installed listed on the permit as horiz. How far can the unit reach to include any acres? is there a law in Pa. as to how far? I read at one site that the unit for horiz. cannot go any further than the horiz. drill bit is capable of drilling horizontally and that if a company actually applies for a permit they must produce the confirmation that they have that kind of equipment to drill that far for the size of unit.
I also read that usually this is only about 2000 to 3000 feet (not confirmed info). Therefore if your property is located past the reach of the horiz. drill bit...and they only put in a vertical well with a future plan for one horiz. well ...how can they hold the acreage in the unit?
I just found this link...good info. about drilling horizontally. Would still like to know if any of you know just how far the horiz. drill can technically go for the marcellus and if there are statutes in the laws of the states regarding such.
I mean if a drill company can obtain a permit for a unit of let's say 1300 acres ..if at obtaining the permit they only have one vertical well though plans for a horiz. later...can they hold for production acreage that isn't that near the vertical well?
Sam...you wrote this in a prev. post here..
Many wells are drilled for about 3/4 of a mile, it may even be the average length and draw for a width of probably 500' counting both sides of the horizontal line. If you do the math, that is about 80 acres per well. With 4 wells on a pad, 2 going NNW and 2 going SSE it looks like about 360 acres in a rectangle 1.5 miles long by 1000' wide, maybe the size of a unit.
Of course with 10 wells from the drill pad, 5 in each direction, it might be 800 acres about 1.5 miles long by 2500' wide -- forming a unit - but that does not mean all 10 wells will be drilled at the same time.
Is there a link to this info somewhere or text that you can recommend...I am trying to learn about this? thanks...and thanks surely for introducing this topic!
They are currently drilling the horizontal legs anywhere from 4,000 feet to near 8,000 in Western Pa.
In Pennsylvania, for Marcellus wells, there is no regulation whatsoever for the size and shape of a production unit or for the setback distance for a well from the unit edge. Eventually this will been seen as a huge mistake which allowed drilling companies an enormous profit advantage.
In my area of SE Bradford County in PA, each horizontal well is permitted to be about 5000 feet long and about 1000 feet from the next horizontal well of the 6 normally placed on a single well pad. A normal unit is a rectangle about 10,000 feet by 3,000 ft. I made a diagram to show this.
In SE Bradford county wellpads are regularly spaced and one or two wells have been drilled per pad. The maps from the gas companies show regular units perfectly covering the entire area. However in practice, the units they declare are hardly ever simple rectangles. The latest tactic is to declare 3 or 4 units for a single wellpad. This way 2000 acres plus can be controlled by one wellpad. I don't see how these units can be used for production - I think at some point the units will be reformed to suit production needs, but presently many acres of leases are held. I have included an example of the Felter and Merryall units. I think eventually another wellpad will be placed between these wells.
Just for fun I have included the Berend-Ross unit which is in four separate pieces. How can that even be a unit?
Essentially, the rule is - there are few rules.
The exploitation of the Marcellus Shale is in its infancy, only really 4 years old; it has another 40 or so years to go.
I look upon Pooling (Unit) size as a perverse sort of game: a combination of Jig Saw Puzzle, Monopoly, Risk, Battleship and Liar’s Dice.
One would think that the size of a Unit would be determined primarily by Geologic, Engineering and Production Economics criteria. Reality is that many non-technical factors can interject into the decision process; some of those factors ignore the technical factors.
Company A has accumulated leases on “X” acres. Leases that will be running out in 8 months.
For the area that Company A has accumulated these leases, they have determined (on a technical and raw economic basis) that the best parameters are for a four well pad with 3000’ horizontal legs (two legs oriented NNW, two oriented SSW). The ideal unit size is determined to be 6000’ x 1600’ (220 acres).
Now, natural gas prices are currently low; cash flow sucks.
Company A wants to hold all of their “X” acres, held by leases that are fast expiring.
Company A proceeds to send out Modification Agreements, attempting to Pool the “Mullets” into as large a Pooling Unit as possible. They then attempt to get a rig on each of these Units, before their leases expire.
On Unit 1, they were able to Pool 900 acres, they permit and position a four well pad, setting conductor pipe for four wells and drill only one horizontal well (before moving off location). They state their intention to eventually return and drill the other three wells. They intend, at some time in the future, to return and redo the unit boundaries (splitting to add units) and drill out the full 900 acres (eventually planning to drill 16 wells total – on four pads). But in the meantime, they have tied up all 900 acres with one horizontal well, the full acreage Held by Production. (HBP).
On Unit 2, they were able to pool 450 acres, they permit for one vertical well. They drill a cheap vertical well through the Marcellus, as a vertical well, it produces very little (only the 60’ vertical thickness open to the borehole). They argue that they need to drill the vertical well first, in order to evaluate the best parameters for future drilling. They intend to return in the future and re-enter the hole and kick out as a horizontal well – as well as break this up into two units with an eventual 8 wells total on two pads. But, for the time being, they have cheaply tied up all the acreage (for an indeterminate period of time). All 450 acres are HBP (and the Lessors are getting their monthly checks for something minuscule).
These are simply two hypothetical examples of what Company A might do; there are countless other similar possible actions that Company A might attempt.
What Company A can do is a function of the verbiage of the various Leases that they possess, the verbiage of the Lease Modifications that they can persuade the “Mullets” to sign, the ingenuity of Company A’s staff in gerrymandering pooling units (such they can tie up the maximum acreage at minimal expense).
There are a lot of companies out there that have greedily accumulated more leased
acreage than they have either the time or resources to fully drill up prior to lease
expiration. They have made a lot of promises that they are not in a position to keep (but,
as many of these promises were verbal – they have little meaning) And, this is
compounded by the reality of natural gas prices too low to allow profitability. They will
run around like a bunch of “rats in heat” trying to hold as much acreage as possible - as
cheaply as possible. They will try to cobble together the largest pooled units that they
can, and drill them in a manner such that their initial costs are as low as practical.
How realistically put....Jack, and how thoughtful for you to share that.
I have been on the phone with a clerk at DEP for over an hour figuring out how they permit wells and report data. If any of you want to call it is the Meadville ofc. in Pa. that will respond to questions about the report.
http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-81979/5500-F... (on the map but scroll to the map is the tel. number) this page has good info ...the Pa. dept is not very well staffed for this kind of follow up regarding units, etc. in actual knowledge of what is really installed in the field site.
I have found that we cannot rely on using 1H, 2H, etc. as meaning 'horizontal'. Yeah, it may mean horizontal for that oil company as a means of numbering but the DEP only depends on the yes or no where the question is ..is it horizontal yes or no. Some oil companies do use the numbering system of 1, 1H, 2H, 10H as how many wells and whether horizontal or not...but the DEP report only lists the names of the wells reported by the oil company in that column.
Now upon application with a permit the oil company should be not considering the well status as 'active' as it is not yet installed. When it is installed they are to report it as 'active' for production (which is a one year permit), inactive status (which they can hold for 5 years without a new permit), and there is also the RINAC which the clerk thought meant regulatory inactive status. I inquired what the status should be if the well is not producing because of no pipelines...was told it should be considered inactive not active. Almost all the areas not producing cause of no pipelines are listed as 'active'...if that tells you something. They are not staffed to check the permits from that office as to whether the well was actually installed or not. If you use the production report be sure to look at the comments section as geology.com does not list the comments on their production report that they index from the DEP report. I found that some wells were shut in back in early 2011 yet they are reported on the production report.
In conclusion...this takes time to find out info about your unit, the wells if installed or just reported as if they were., etc. and I have found that the state of Pa. is not geared up to be a watchdog yet over all of this. very disappointing...and the game of lier's dice (as Jack mentioned above) may very well be the game being played out. people that live on the sites or near them should have someone walk over and actually see if the wells are indeed installed rather than just accept that their acreage is being held by production. In the post above (again thank you Jack) the mention of a horizontal well holding a large unit to extend a leases (leases) really makes a difference if it is really a vertical well on one of the lease holders property (if stated in your contract what type of well would be considered production ..see a lawyer to validate as I am not a lawyer...just sharing what I am learning with you). and is not a horizontal well yet. For some leases may require that an actual vertical well be on the same leasehold acreage (not your neighbors) to extend the lease.
i do not consider relying on these permits as establishing whether a well is installed or not and holding the unit leases in extension. There must be much more to consider and it is time to call a gas/oil attorney to see what really is legitimate considering a unit and if they have not really installed wells though a permit has been issued ,...then can they really extend the lease. Perhaps with only a well pad with a pilot hole? (just learned that word with the clerk...pilot hole not necessarily means a well though could end being a well). Indeed some of these oil companies have done what Jack posted above as,
They argue that they need to drill the vertical well first, in order to evaluate the best parameters for future drilling. They intend to return in the future and re-enter the hole and kick out as a horizontal well
meaning find out if your lease requires a horizontal well to hold your lease. For the permit dept. only knows whether it is vertical or not by the yes or no in the column regarding horizontal...not necessarily by name of the well.
I think it is time to call State Rep. Garth about his comments about units (see below post).
it took me over 2 hours to do all this so far so I hope some of this info helps someone else also.
There is no precise answer to some of your question.
Pennsylvania does not have a law limiting the size of units [unless it is in the Oil and Gas Conservation Act which I do not expect to be used]. Some states have the driller submit information for approval of the size, shape etc. of a unit.
Units might logically be what can be gathered at one well pad.
I think I have heard of horizontal wells up to 2 miles, but that kind of number may not be too useful because it is a moving target. I have read that Range's [one of the more prolific drillers] wells average something over 3500' and something like 3/4 of a mile long for a horizontal well to be rather typical. If a typical well is about 3/4 of a mile long then with wells going in two opposit directions you are probably talking about a rectangle about 1.5 miles long.
The number of wells on a pad varies. As you have observed, more wells on a pad means fewer pads. Probably the minimum would be 4 - 2 going NNW and 2 going SSE. A couple of wells in each direction means the 1.5 mile rectangle would be about 1000' wide. [a couple more wells in each direction would widen the rectangle to 2000' for example].
The larger number of wells per pad would seem to make sense to reduce the spread of the surface disturbance, but it is an engineering-geologic decision coupled with the available leases etc. Other factors would have to go into the decision of how many wells per pad. It makes sense forth the operator to make units as large as possible so that by drilling one or two wells in the unit s/he can hold more property and leases beyond the primary term. There is no way that all the potential drilling can be done all at once anc the companies want to have reserves for future drilling to back up all the plants, pipes and inrastructure for years to come. It is unrealistic to think it will all be drilled at once.
Make your guesses and do the math as to the size of the unit or pool. Try to find out what the big operators have been doing. The lines of the unit will have little to do with surface property lines and insisting that land that is not a logical part of a unit be included in the unit may work to the ultimate detriment of the Lessor.