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November 2014

Well Spacing...

Posted by bernell on November 6, 2014

Bear with me.  I’m going to rattle on about a subject that, in time, will be of great interest to people in the TMS.  I’m more or less just introducing a subject that we will be discussing much more in the future.


Determining the commerciality of the Tuscaloosa Marine Shale has been a long, slow process.  All agree the last hurdle to determine the viability of drilling individual wells in the play is to bring down the costs a little more.  Most agree the goal is $10 million per well and that this is attainable.

But, assuming this goal can be attained and the question of whether drilling here at all makes sense, the next question to determine the true value of the play and acreage in the play is to determine the spacing of wells.

If only one well is drilled per 2,000 acres, no one will be happy in the long run.

So, multiple wells will have to be drilled in these gigantic 2,000 acre units. Many questions have to be answered in order to know just how many wells can be drilled.

Among the most obvious things to determine is exactly how far apart can these wells be drilled before they begin to “communicate” or take away from one another.  In other words, how many wells is it possible to drill per unit?

As it was explained to me, when a well on one side of another well is fracked, the formation on that side is loosened up somewhat.  This sounded like it could be a good thing to me in that fractures created from the fracturing of the second well would most likely go further on that side of the fracture. 

Unfortunately, my first thought was not quite on target, since these pressurized fluids will follow the path of least resistance it also means the fracture on the opposite side would likely be limited.  So, perhaps the fracture would extend 400 foot to the west and only 100 foot to the east, while normally the fractures only spread 200 foot or so to either side.  This could really complicate things. 

So, how can these companies really know?

Answer: Experiment.

I don’t know about other companies, but the experimentation process started very early for Encana. 

For example, on some of Encana’s early wells, they had a micro seismic study done while they were fracturing.  I’m not sure of how many tests were conducted, but I know it was done on the Anderson 17H-1 and Anderson 18H-1 wells drilled in 2012. The micro-seismic studies could supposedly tell EnCana how far the fractures spread from the hydraulic pressures applied.

But, even with micro-seismic studies, you still have to actually drill wells to determine for sure what will happen.  Specifically, the Anderson 18H-1 well was set to be drilled 500 foot west of the east side of the unit line while the adjacent well, Anderson 17H-1, was set for drilling 825 foot east of its west unit line.  In other words, these wells were planned to be 1,325 foot apart.

To my knowledge there has never been any “communication” between these wells and the fracturing of these wells had no adverse effect on one another.

So, early on we got a pretty good idea that wells planned for drilling 1,325 foot apart would be fine.  This would allow for 8 wells per 2,000 acre unit. (5,280 foot wide divided by 1,320 foot equals 4.  Four wells north and four wells south equals 8 total wells in a unit.)

The next experiment on spacing that I am aware was also conducted by Encana when the Anderson 17H-2 and 17H-3 wells were drilled.  The 17H-2 was set 660 foot west of the the east side of the Anderson 17H unit and the 17H-3 was set 1,320 foot west of the east side.  In other words, these wells were set 660 foot apart, a distance that would allow for 16 wells per 2,000 acre unit.  (5,280 divided by 660 = 8.  8 drilled north and 8 drilled south would equal 16 wells.)

While I don’t know the details of the outcome from these last two Anderson 17H wells, I do know that there has been at least some communication between these wells and there has been intensive study done on this communication.  The 17H-3 was shut down for all of June and most of July and I believe this shut down was a part of a study to determine what difference it would make in production. 

While daily production information and “signature” chemicals in various stages would be of more value to helping one understand precisely what is going on between these two wells, all we have is monthly information as laymen in order to try to understand what is happening.

So that’s what I’m providing below as we (I) attempt to understand what sort of “communication” was occurring.

Here is barrels of oil production per month before, during and after the shut-in test for 17-3:

                                17H-2                    17H-3                    Total

April                        2,133                     2,963                      5,096

May                         1,491                     2,401                      3,892

June                         2,841                     -0-                         2,841

July                          3,679                       419                      4,098

August                      2,962                     2,582                     5,544

I would include September information, but these wells didn’t produce for most of September, likely due to completion efforts involving the Mathis well.

When studying the numbers above, it appears there was also something done to enhance the production from both wells since total production in August was greater than May (not the norm).

Despite this bit of confusion, it appears to me that production from 17H-2, in fact, did improve somewhat while 17H-3 was shut down, though this improvement in production was not enough to equal to the total from both wells. 

So, when wells are drilled side-by-side, it would appear the spacing needs to be a bit greater than 660 foot.  Right?


Suppose the “communication” is only occurring because of the weakening of one side because of the fracturing of the other well on that side?  Ahhh…something else to study.  (Remember 400 foot and 100 foot...the 400 foot due to the weakening of one side from an earlier fracture.)
Here is my theory. 

These wells will likely end up being spaced such that at least 14 wells and maybe 16 per 2,000 acre unit will be drilled. 

I believe these companies will ultimately move to a interlacing “tong” drilling plan whereby wells will be drilled 1,320 foot apart in one direction, fractured and completed.  Then, later, wells from the opposite direction will be drilled, also 1,320 apart, but spaced 660 foot from the opposite direction drilled well.  Think of two forks or tongs being intertwined or of slipping the fingers of one hand in between the fingers of hand pointing north, one hand pointing south.

By doing so, the weakening will be equalized on either side of the laterals for the second set of wells and the fractures, while perhaps spreading further, would not likely extend quite as far to either side as if only one side of the lateral had been fractured.  So, perhaps both sides would spread say 250' or so rather than one side 400 foot and another 100 foot.

All this said, what led me to write about this is that we’ve mentioned the 4 well drill pads planned for the near future.  These wells could provide another spacing study time.  Unfortunately, if you space too closely you run the risk of ruining a well in one unit while enhancing a well in another…not a subject an oil company would want to deal with as, over time, a legal battle could develop over proper revenue sharing between units.

So, what is needed (and what I have heard rumors that may be coming) is a study within a unit.  Wells could be drilled within a unit, as was in the case of the Anderson 17H-2 and -3 wells without fear of causing income sharing questions in other units.

Stay tuned as this play continues to evolve, folks.  It is going to be a much longer ride than I first anticipated, but it doesn’t appear it will be any less interesting for the entirety of the trip.

What do you think about it?