I recently joined the forum and wanted to contribute from a technical perspective. I’m a reservoir engineer with 15 years of experience, having worked in major oil & gas companies as well as with private operators.
One recurring observation in mature or low-rate wells is that production underperformance is often attributed to reservoir depletion, when in reality the limitation may be operational or surface-related.
This can create confusion between:
True reservoir decline
Mechanical or artificial lift constraints
Surface handling or backpressure effects
From a technical standpoint, distinguishing between these factors is critical before drawing conclusions about remaining potential.
For those willing to share:
When a well underperforms, what data or indicator do you personally trust the most to decide whether it’s a reservoir issue or something else?
Welcome to the forum! Love to have more technical experts on here.
I will add a few comments from the geologist side since the reservoir engineers often work with us as partners.
-“underperformance as a definition” -what was the original benchmark? Was is a generic type curve from many wells, but too far away or was the decline curve based upon very close wells and comparative wells-parents or children, similar completion techniques or different ones, etc. What years were the wells drilled in and how were they used for comparison. Are you using the same reservoir for comparison? What equations were you using for decline-were they the same? What were the perf spacings on the different wells? Water volumes and chemistry, frac sand or beads?
-Long term under-performance or short term? Were wells shut in due to nearby frac’s one time, several times, Covid shut-in? What pressure monitors? Were fields left to rest and then turned back on for better recovery? Gas recovery or oil recovery? What is the GOR change over time after frac water recovery? Are you doing regular chemistry testing for scale?
-scale issues due to water chemistry? Were cleanups done?
-sand encroachment due to screen failure?
-geochemistry testing of hydrocarbons in the well? Are you getting incoming mixed volumes from a different horizon due to a fault nearby or is the fault a thief zone?
-We are in the business of pressure decline, so where is it going?
-Pipeline constraints, flared gas versus produced gas, any secondary recovery efforts?
I’d like to talk about how many producers today fail to efficiently use the remaining energy of the reservoir. In many cases, there is no clear understanding of reservoir symmetry and behavior, which limits the ability to design effective injection plans. This is compounded by a lack of understanding of how the subsurface is actually configured, ultimately constraining operational decisions. As a result, reservoirs that could achieve recovery factors on the order of 25% often end up recovering only 10%, not due to true geological limitations, but because of incomplete reservoir management and poor utilization of remaining energy.
Great subject. I would like to hear your thoughts on gas wells in the far Western Haynesville. Look at the difference you see in Comstock wells and Aethon wells. Look at Aethon’s Curry #2 for example. Also look at Aethon KODA and then look at pretty much any of Comstock wells. Comstock Circle M Alloc right next door to KODA. Why do you think Aethon’s wells look like they show so much more life? How much longer can the Aethon wells keep producing at near peak production?
From my experience in gas reservoirs, especially shale gas systems, I think it is critical to look at regional geology and the structural framework before comparing production curves alone. Gas, being far more mobile than oil, is highly sensitive to the type of trapping, lateral continuity, compartmentalization, and overall connectivity of the reservoir.
In areas like the Western Haynesville, relatively small variations in effective thickness, original pressure, rock quality, and regional stress regime can result in significant differences in well longevity and the ability to sustain near-peak production. For that reason, beyond completion design and choke management, understanding the macro-scale geology is key to explaining why certain operators or wells appear to show much more “life” than others.
From my limited understanding, one of the different technologies Aethon uses other operators may not have is a dynamic variable choke. It is used to optimally maintain the well/reservoir pressure which keeps the fractures open longer and preventing them from collapsing.
That is correct. These types of dynamic variable choke systems can be calibrated to self-regulate once a full integrated study of the system is performed, including reservoir, well, and surface conditions.
When the optimal operating state is understood—whether the objective is to preserve well integrity, minimize formation damage, or maintain fracture conductivity—it becomes possible to define appropriate pressure and drawdown ranges and allow the system to dynamically adjust within those limits.
The real value lies not only in the hardware itself, but in the engineering criteria used to configure it according to the desired outcome. When properly applied, it is a very effective tool.
There is also the factor that the operator makes money either way due to deal structuring. And it just might not be as good of a reservoir as they had projected