Otis11 + 551 ZP November 5, 2019 On 11/2/2019 at 3:51 PM, D Coyne said: Douglas, I consider an industry consultant as someone who is part of the oil industry, though consultants may see themselves as outsiders. Not sure what the secret sauce is in the recipe, but from a physics perspective I would agree with your perspective. I imagine Conoco drills its wells in the sweet spots as their average Eagle Ford well looks like it will be about two times the EUR of the average Eagle Ford well for all producers in the basin. Seems the claim that wells are recovering 2 times the oil in place as before is highly unlikely, seems to be a case of wishful thinking or investor hype. So I don't officially have anything to add... Completely unofficially, changing the amount of propant, pH, pressures, frac speed, etc can have significant impacts on EUR even for minor tweaks (significant enough to justify very tightly controlled processes and using AI to figure out what affects what, uncertainty interval of each variable on the effect, etc). Improved drilling techniques have a huge impact (though no significant cost impact - not a drilling guy so cant even attempt to explain this, but seen the data to prove results) and again, only marginal cost implications (marginal as in 10% increase in cost on this single line item, but 8% improvement in production meaning cost improvement per barrel. Numbers made up as illustration. Couldn't release real numbers for anything...). Finally, just designing controls for how the well is brought on and how it is shut down in emergency shutdowns or facility shutdowns impacts EUR. (If you dont know this you're probably damaging your wells and not even realizing it... ). Absolutely minimal marginal costs... increased EUR. Most of these are so slight, someone supplying material for this well wouldn't realize a difference, but the person doing the work would... and it has real results. Quote Share this post Link to post Share on other sites
D Coyne + 305 DC November 6, 2019 On 11/5/2019 at 1:10 AM, Otis11 said: So I don't officially have anything to add... Completely unofficially, changing the amount of propant, pH, pressures, frac speed, etc can have significant impacts on EUR even for minor tweaks (significant enough to justify very tightly controlled processes and using AI to figure out what affects what, uncertainty interval of each variable on the effect, etc). Improved drilling techniques have a huge impact (though no significant cost impact - not a drilling guy so cant even attempt to explain this, but seen the data to prove results) and again, only marginal cost implications (marginal as in 10% increase in cost on this single line item, but 8% improvement in production meaning cost improvement per barrel. Numbers made up as illustration. Couldn't release real numbers for anything...). Finally, just designing controls for how the well is brought on and how it is shut down in emergency shutdowns or facility shutdowns impacts EUR. (If you dont know this you're probably damaging your wells and not even realizing it... ). Absolutely minimal marginal costs... increased EUR. Most of these are so slight, someone supplying material for this well wouldn't realize a difference, but the person doing the work would... and it has real results. Otis, No doubt all of these can affect EUR, but after a while the process gets pretty dialed in so that each operator follows best practices and there is little further improvement average new well EUR for a given optimal lateral length, proppant loading, frac fluid etc for an optimally designed well. For the Bakken, Eagle Ford, and Permian basin they may have already reached this point as there seems to be little increase for the past couple of years in EUR per foot of lateral. In some cases a particular company may have better average results because most of their wells are in the sweet spots and other operators may have fewer tier 1 wells, so their average EUR will be lower. I focus on the field as a whole, which eventually will run out of new well locations in Tier 1 acres, at that point we will see average new well EUR per foot of lateral start to decrease. When that occurs breakeven oil price for the average well will increase for any assumed price for natural gas. Quote Share this post Link to post Share on other sites
Otis11 + 551 ZP November 6, 2019 2 minutes ago, D Coyne said: Otis, No doubt all of these can affect EUR, but after a while the process gets pretty dialed in so that each operator follows best practices and there is little further improvement average new well EUR for a given optimal lateral length, proppant loading, frac fluid etc for an optimally designed well. For the Bakken, Eagle Ford, and Permian basin they may have already reached this point as there seems to be little increase for the past couple of years in EUR per foot of lateral. In some cases a particular company may have better average results because most of their wells are in the sweet spots and other operators may have fewer tier 1 wells, so their average EUR will be lower. I focus on the field as a whole, which eventually will run out of new well locations in Tier 1 acres, at that point we will see average new well EUR per foot of lateral start to decrease. When that occurs breakeven oil price for the average well will increase for any assumed price for natural gas. I fully agree with you that these will get pretty dialed in as best practices, however I'd argue that this has not yet occurred. Ok, it may have occurred for some of the items cited so that the majority of new wells are more or less optimal for those parameters, but not for all. I can still cite some of those parameters that some producers are continuing to optimize, while others aren't. And within those who are optimizing it, if you look at the data you can see correlations in the data as they attempt to improve their EUR. Now, they could just be getting lucky and drilling the sweeter spots on the same wells they're testing these new parameters, but I'd argue, given what I've seen, this is not a likely case. Now, I have no data to publicly share, so believe me or disregard me at your will. My argument would be that the obvious parameters - those that are easy to collect data on and easy to optimize have been. However there are many more things that can be optimized, but haven't. Just look at proppant loading, this would seem fairly straight forward, but have you corrected for frac pressure, oil density, oil/gas/water cut, back pressure, etc? You can't optimize for each of these independently - that would only find a local maxima. There is still room to gain by reaching the global maxima, but this is much harder to realize. This one may not be the best example either, (especially since proppant is not an area I have experience with, but I can't talk about ones I do have experience with) because it has been given lots of attention and - to my understanding - is reasonably straight forward to correlate data with result. But what about others that are less clear? Just some food for thought - I usually don't comment on these types of things because I get hamstrung with what I can discuss. Hope this is useful. Quote Share this post Link to post Share on other sites
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