This is food for thought and not infallible assertions by an LTO expert by any means. Actually, I fully expect to be wholly refuted or simply dismissed as a fool in his mother's basement with time on his hands. As a long time conventional production engineer and owner/operator I seek understanding on my part and that of others. For years I have been trying to visualize and understand unconventional reservoirs and the wells and artificial fractures that are imparted to drain those reserves. Not being a reservoir engineer with the skills necessary to understand virtually zero perm but variably natural fractured rock, LTO reservoirs, my approach has been simple and an extension of conventional reservoir thinking. For the most part these are just the mental machinations of a guy that always has more questions than answers but who knows that the answers mean something important, so bear with me. In various posts here and on POB, a debate rages over GORs, government expert recoverable reserve estimates and company and/or spectator EUR projections both pre and post production. The percentage of TRR varies by region and rock but I have often wondered how those numbers are derived. Furthermore, I wonder how those numbers are revised after the first well is drilled in a unit. So many articles and posts have been published offering theories and data related to lateral length, well spacing, frac size, proppant quantity, size and loading, parent vs child wells, GOR variations and so much more that conclusions of value seem to get lost in the weeds. The aftermath is plain to see. Logically, the primary objective of exploitation methods of any reservoir is to maximize EUR typically by maximizing reservoir contact. In a "conventional" reservoir where the permeability is much greater than zero or even fractions of a darcy this would appear much less critical than an unconventional reservoir where the permeability is close to zero in microdarcies. Of course, natural fractures exist which enhance the gross effective permeability of those LTO reservoirs. My concern lies in the reduction in contact area of tight rock by not that closely spaced wells and massive frac jobs, natural fractures notwithstanding. This concern is born out of the counterintuitive stimulation theory of tight carbonates moving away from fast, hot acid jobs (high intensity) if you will, to weaker acid pumped at lower rate jobs (low intensity). A paper was written maybe 20 years ago on the topic. The general premise was that higher intensity acid stimulation treatments created longer or wider flow channels from the vertical wellbore but the lower intensity jobs created more flow channels nearer the well. Obviously, X units of acid can only dissolve Y units of rock so the question is where is the removal of rock the most beneficial? Theoretically, having more "cobwebs" of small flow channels would be better than larger, longer flow channels. My reasoning for the benefit has to do with more intimate connections of pore throats, drive mechanism and produced fluid characteristics. Logically, there is an optimum middle ground based upon fluid propertied and resulting flow channel diameter but that is beyond the scope of this extrapolation. For a given drive mechanism the connection and fluid properties are important due to pressure drop concerns while flow occurs. I will focus on oil production. To reduce the distance that oil must travel through any area of pore throats will reduce delta P thus increasing flow rates and minimizing relative permeability side effects. In my opinion, the most damaging side affect is gas breakout from oil due to delta P and the stranding of oil in the process. At any given level of pressure drawdown or flowrate, the greater the distance that oil most traverse through units of virgin rock, whether inches or feet, to get to sufficient flow channels, the greater the gas evolution and resulting oil viscosity increase resulting in stranded oil. Articles have been written about the modern practice of choke management, which us old guys knew ages ago as pinching the well back, whereby EURs increase with less drawdown and sometimes higher flow rates. However less drawdown typically means less cash flow. LTO oil reservoirs are effectively solution gas drive. The nature of solution gas drive reservoirs, which is exacerbated as noted above, is the reduction of theoretical EUR in order to flow the reserves. However, when using the imprecise BOE metric, those reserve reductions appear less than are real. A partial solution to that conundrum is to provide pressure maintenance of the reservoir. Optimally this would be most effective by gas injection at or near the time of first production or the very wide spacing of wells which increases EUR per well but not per unit area. Neither of those solutions are going to happen. What is left is the connection of porosity. More intimate connection is defied by massive fracs and tight well spacing, each having its own drawbacks. Tight well spacing is a no brainer, as well interference cannot be corrected to the best of my knowledge resulting in massive areas of bypassed porosity. Massive frac jobs effect the same as tight spacing by frac hits but also in more insidious ways I think. Extending the logic of the high versus low intensity acid stimulation of tight carbonates, big frac jobs seek to extend far from the wellbore and intersect the maximum amount of natural fractures present. In highly naturally fractured rock that sounds great but my guess is that such rock would be somewhat productive without a frac. Seems as though we had some unfracced Middle Bakken wells years ago that produced at low rates but produced nonetheless. That may be apples and oranges here. But let's say that the rock is not highly fractured. On a macroscopic level, the frac fluid will seek the path of least resistance and travel a distance somewhat proportional to the job size. What happens to all of the rock, on a more microscopic level, that is not functionally adjacent to a propped fracture? By my reasoning the oil must travel further to get to a sufficient flow path resulting in higher delta P and/or the delta P is increased across said rock due to the much higher permeability of the propped fracture at a given drawdown. If the LTO revivors were highly acid soluble carbonates the problems could be somewhat mitigated but they aren't. The common thread in the improvement of currents EURs is economics. The common thread of ultimate EURs is mechanical thus limited and truly unknown as of yet. These two considerations are functionally mutually exclusive at some point. Either way, I don't think we ever hear the truth, the whole truth and nothing but the truth or a reasonable approximation thereof. Honestly, I cannot be correct or mostly correct but this bugs me to death. Anyone that can line me out please do so by teaching and not simply berating. I had a tough nun in the 2nd grade with a long ruler and I'm not certain how much I learned that year.