Depends on the location of the section. The state allows a maximum of eight per governmental section +/- 640 acres. Some drilling units are larger especially those along the state line which are usually a section and a half so in those instances 12. Operators started out drilling the eight allowed by the state but have "up spaced" to six per governmental section owing to more intensive frac designs. Where a section has both Haynesville and Bossier shale reserves, double those numbers. I have seen a few instances where it appears an operator drilling long lateral wells will use five wells to drain a section.
As for what operators are doing, I would not say six per formation. I have seen LOTS of recently drilled units spaced with four wells. In recent years, you see six, five, four. There is no guarantee that an operator will ever come back and fill in more density once they space them out. In fact, they may still be experimenting to see if four or five will turn out to be the most efficient use of capital -- to get the most bang for the buck in an attempt to drain the unit as much as possible with the fewest wells possible. A mineral owner likes the most wells possible, assuming proper operating practices so as not to damage the reservoir, but an operator wants the best return on investment. And they are footing the bill. As a mineral owner, I would much prefer six versus four because as I said, they may never come back and drill infills inside those four. And may not need to in order to drain the unit. We'll see, let's check back in ten years!
Six is the current average although there are variations depending on the number and placement of existing wells. With intensive frac cylinders, there is nothing to come back and infill for. Chesapeake has some pretty unique lateral paths in their recent alternate well applications. Laterals that bend around existing wells. In some of those it appears the company thinks they can drain Haynesvillle reserves in a section with five total wells. There is a difference between Haynesville laterals which have to take into account existing well paths and Bossier wells that often do not. Where there are no existing Bossier wells, operators are spacing for six.
Skip I'm sure you've posted this before but when using SONRIS how can we determine existing wells drilled per section?
On the SONRIS well file, scroll down to the LUW Production section and click of the six digit code number. I like to use the unit well for this but you can do it with an alternate unit well as long as you remember the correct unit name when looking at HC wells that produce from more than one unit. The LUW search avoids the problem of unit wells drilled from surface locations off the unit. You then have a list of all the wells for a unit regardless of surface location and you can click on each to see and copy the well plats. You want to see not only the number of wells reporting under that LUW code although that will answer the question of the number of existing wells in the unit, you want to see where each lateral is located within the unit. You can then look at the units to the immediate north and south to see if undrilled lateral slots line up for long lateral HC wells which operators prefer. Operators still drill short lateral unit wells where the remaining slots do not line up for HC wells when that is the only option.
I remind mineral owners that long laterals benefit the operator but not necessarily the mineral lessor. The long laterals enable the operator to produce the well volume at a lower cost per mcf. What benefits the lessors in each unit is the high intensity frac which makes the well or portion of the well lying in their unit more productive.
I hate to repeat myself but it is the high intensity fracks that benefit mineral owners, not the length of the lateral in HC wells. The one caveat to that is the 330' set back on the north and south ends of each unit that are not stimulated in a unit well. We are constantly amazed at the Initial Production volumes of the long lateral HC wells: 25 to 45 million cubic feet per day. However divide that volume by the number of units included in an HC well and you get somewhere in the neighborhood of 12.5 to 15 million mcf per unit. That is very close to the same you see with a one unit well, there are just two or three units producing that 25 to 45 million cubic feet per day. Where possible operators prioritize long lateral HC wells for the lower cost per mcf produced and the ability to stimulate two to four set back zones which add to the production.
You're welcome. So much of the Haynesville Shale fairway is in advanced stages of development that the options for drilling laterals are becoming somewhat constrained. After a period of predominantly long lateral HC wells, we are now seeing a good many shorter lateral alternate unit wells. Companies like Aethon and Paloma drill quite a few when there is no option for a long lateral well.
28 is a Comstock operated HA unit. It has five wells and all look to be Haynesville completions based on TVD. Based on six per reservoir, it appears that there are one remaining Haynesville lateral slot and room for six Bossier laterals. I believe that sixth Haynesville slot already has a Field Order. Applications for alternate unit wells often are for more wells that an operator will drill at one time. You can't add new volume beyond the spare pipeline takeaway capacity.