1. Most new wells will be 7500'-10000'K CUL's drilled to within the known boundaries of the HA and BO Shales. Some shorter laterals may be drilled due to offset operator ownership or previous legacy wells.
2. Land/Mineral Owners need to educate themselves on the drilling and completion of these wells as the pay deck is based on allocation by perforated foot. Sections share the production based on this allocation.
3. Many of these wells are drilled from surfaces in other sections before the lateral is begun so the permitting process can be confusing--download the location plat to see the actual path of the wellbore. Just because the surface is in Section 32 does not mean that Section 32 will share in the wells production.
4. With this in mind, many landowners can receive additional bonuses from subsurface easements and well pad rentals that may be out of the unit being drilled.
5. New pipelines are being laid all across the Haynesville--if you allow a pipeline under your property keep in mind that this document is just as important as a lease agreement and use professional representation if needed.
6. Many operators are allowing the more active operator in the section to drill in a shared section so it may not be "your" operator that actually drills the well. Pay attention.
7. Learn to navigate Sonris for LA land/mineral owners. It is free and has most all of the information you need. I have no advice for the Texas side--my attempts at the RRC website have not been good.
8. The decline of the new, properly drilled and completed, CUL's in the core are vastly different than the original legacy single section laterals. Make sure you are educated to these volumes. Not all operators drill and complete the same kind of wells. The type of completion will make a difference in the EUR (estimated ultimate recovery).
9 Monitor old legacy wells for production. If an operator sees a well approaching an economic limit they may do a re frac to boost production and delay CUL's.
10. Enjoy this period of good natural gas prices and thank God you don't live in Europe this winter. Due to a myriad of mis- steps (some natural, some political, some environmental) there is a chance Germany el al runs out of NG this winter.
I actually fear for the Europeans this winter.
Can someone explain the difference in decline rate?
The newer cross unit lateral wells have more proppant per foot along with a longer lateral. Therefore they have more of the reservoir exposed to the wellbore which results in a shallower decline. The original wells would exhibit declines of 75% or more for the first year. The newer wells are shallower than this. Hope this helps.
There are several factors that impact the early-time (first year) decline rate. As ShaleGeo mentioned, the completion designs are far more intense in recent years relative to wells completed in the 2009-2013 period. The combination of longer laterals, tighter cluster/stage spacing, higher proppant loading, and significantly increased fluid loading has increased the early-time productivity of new wells.
One often overlooked factor is the different operating philosophies of the different operators. Without flowing pressure data this is difficult evaluate, however the shape of the decline curve provides some information. Some operators intentionally restrict early-time flow to a certain rate or pressure drop fearing that the wells will be damaged if they are flowed too hard. These wells generally have a lower decline rate until the surface pressures approach the gathering system pressure. Other operators are more aggressive early in the life of wells which yield higher initial rates but also higher decline rates once the well is unable to maintain the high initial rate. The gathering system or wellsite facility capacity can also impact the gas rate.
In a $9+ gas price environment I would prefer higher rates today knowing that also brings higher decline rates.
Good points, Ryan. Thanks. I'll add that in addition to a lack of pressure data, we also only have sporadic choke setting data on SONRIS. There is an initial production flow test and then a test approximately every six months or more thereafter. An early flow test can be deceiving for long lateral wells that can take weeks to clean up and reach maximum flow.
Beware of choke settings and pressure data on Sonris. It is not always accurate.
It is likely accurate for that one test on that one day according to the head of the Shreveport District of OOC. In between tests, who knows?
I was typing a very similar response Skip. The reported test data is for a snapshot in time. On its own, the data is not that useful. The trend in the changes in rate/volume per unit drawdown is more valuable to understanding well performance than a single rate or choke size data point.