InfillThinking.com by Joseph Triepke –
June 14, 2019
Today’s guest post comes to us from Hunter Wallace who is Chief Operating Officer at Atlas Sand. Before helping to start Atlas Sand as
one of the original management team members, Hunter spent a decade as a drilling and completions engineer for XTO, Pioneer, and Brigham Resources.
His completions background at leading operators is something that we believe factored into how quickly Atlas Sand has grabbed market share as a new company selling a new product in the proppant marketplace.
His well engineering experience, business acumen, and aggressive market moves (the likes of which John Galt would be proud of) have catapulted Hunter Wallace to prominent status in the frac sand executive scene in record time.
Something we appreciate about Hunter is that he’s not shy to voice his beliefs with a high degree of conviction. Those of you that attended the Petroleum Connection’s frac sand conference last October in San Antonio may remember the audible reaction in the room when Hunter said “NWS is dead in the Permian” in front of 700 sand folks. That’s a moment that will be forever branded into my memory of the local sand boom (if you need a refresher, see point 2 here).
True to form, his guest post today doesn’t hold back or beat around the bush either. Given his completions background and dune sand interests, we asked Hunter to weigh in on the debate over local sand’s impact on recovery rates. While we acknowledge that Hunter helps run an in-basin sand company, we believe the local sand industry has been too quiet in the ongoing debate around downhole effectiveness. So we are grateful that Hunter is willing to share his thoughts on the debate, and we would be happy to consider publishing a qualified response from the other side of the argument. For now, here are Hunter’s thoughts…
Clearing Up The Erroneous Rhetoric Being Thrown Around In Opposition To Local Permian Sand
Written by Hunter Wallace
The first in-basin Permian frac sand went downhole in July of 2017, and since then it is estimated that 45 – 50 million tons have been pumped into more than 7,000 wells in the Permian. Although there has been a multitude of in-basin sand plants built, announced, or currently in construction in various US basins, this piece will focus solely on the in-basin sand in the Permian Basin.
To date Atlas has invested millions of dollars coring not only our open dune deposits but much of the surrounding non-dune areas in the Permian. Our geologic background drove us to secure the open dunes from the outset, and this vast coring initiative confirmed our expectations of superior quality and best in class economic mining efficiency. Additionally, as a former operator in the southern Delaware Basin we have hands on experience and knowledge dealing with some of the deepest and highest pressure reservoirs currently being exploited in the Permian. This combination puts us in a unique position to discuss the merits and feasibility of in-basin sand sourced in the Permian.
In 2017, when in-basin Permian Sand (“PS”) was still an emerging concept, the conversation around adoption was at the forefront. However, despite all the questions constantly kicking up a cloud of dust, there was a very strong confidence just a scoop below the surface. By the end of 2017, just 5 or 6 months after the first PS had been pumped downhole, there were 17 plants which had either opened, started construction or announced their coming construction in the Permian. However, in the midst of this flurry of capital being committed the debate raged on.
While the vast majority understood and accepted that PS would take out the regional Brady Brown players (sand quality was better, and costs were undeniably lower), the big debate was PS VS the long-standing legacy frac sand providing region of the US – ‘Northern White’ (“NW”). This debate was not for the faint of heart either, both sides had a lot to fight for and a lot to lose, because every added ton of in-basin supply being built was adding a ton in excess supply to the market.
It was clear to those in the industry, following the industry, and/or invested in the industry that someone was going to lose; the question was who? Who was on the wrong side of this massive bet? The hundreds of millions of dollars being spent on PS plants or the hundreds of millions of dollars’ worth of legacy NW assets?
As stated above and clearly shown in Figure 1, all the newly built in-basin capacity was adding to an already oversupplied US market. To put some numbers behind it, there was an estimated +/-50 million tons more nameplate capacity than demand before in-basin sand, and today that differential has ballooned to an estimated +/-150mm tons.
This is, and continues to be an unprecedented disruption in the US frac sand industry. Looking more directly at the Permian’s contribution to this disruption, there are 21 total sand plants that have been built there, each costing anywhere from $60 million to $200 million in construction capex, not to mention the cost of land acquisition etc. The vast majority of this activity is in what we call the ‘Winkler Sand Trend,’ which is approximately 30 miles long by 5 miles wide (map in Figure 2 below).
When you consider this all together, it has been an extraordinary amount of capital infused into a very small (and very rural) area, over a very short amount of time. Some may have heard me say this on recent panels or other public speaking engagements in the past, but I personally don’t think there is anything more analogous to the infamous California gold rush than what we have just experienced over the last two years in the Permian sand play.
So now here we are in the middle of 2019, almost exactly two years after the PS phenomenon began, and the market, or rather its customers, have answered those burning questions surrounding adoption. The vast majority of E&P Operators (“Operators”), especially the larger players and sand consumers, have fully adopted and publicly endorsed PS. Here are a few examples:
• “…what we’ve seen is that the in-basin — the finer mesh sands actually have
produced very strong results. There was no difference in results. And as a result, there’s no reason not to take advantage of the cost savings.” – Timothy L. Dove, Pioneer
• “…we’re very pleased with the performance of our — the sand we get in basin. It’s working great for us. So no concerns whatsoever.” – Daniel E. Brown, Anadarko
• “Currently, we’re focused on using local sand. Certainly in the Permian, that’s a big cost saver for us and certainly the industry, too. So we’re going to continue to do that…” – William R. Thomas, EOG
• “And even with the busy environment, the team has done good work fighting inflationary trends by getting more efficient and increasing our use of Permian sand.” – Timothy Leach, Concho
• “We’re probably at 90%, 95% local sand use now in our entire Midland Basin program and have seen significant cost savings associated with that…” – Javan D. Ottoson, SM Energy
These quotes are only a small handful of the public statements out there. Furthermore, and arguably just as importantly, there has yet to be an Operator publicly state that they are converting back to NW. So, as you can see the debate is largely over as far as the customers/Operators are concerned. They have voted with their wallets and the winner of that multi-million dollar bet is PS. However, these Operators have had the advantage of being on the frontlines for the last two years pumping the PS and watching the production data from their wells as well as observing some of their neighbor’s/partner’s wells to be able re-affirm the move away from NW was the right decision.
On the other side of the fence, there is a very large population of people that follow our industry who are not privy to that data and they continue to hear the same propaganda from sources essentially stating the customer is wrong. Without seeing the well results over time for yourself and continuing to hear supposed ‘industry experts’ say things like, “there are still questions on in-basin Permian sand”, “NW will always have a place in the Permian”, or most recently, “Operators will switch back to NW in the Permian” it is understandable you might still have some questions. This population deserves to get a little more insight into what is going on, and I hope the rest of this information is helpful for that group.
Looking at things purely from a 30,000’ view I would hope reading the above quotes from the Operators themselves, gives you some pretty strong conviction in believing that the debate is really over in the Permian. It goes without saying, but probably worth reminding everyone that the Permian positions of these Operators are some of, if not the most valuable assets that they have in their entire portfolio (most by a healthy multiple), and they have a very strong vested interest to make the right decisions around the development of these positions. Or to be more blunt, they are not
incentivized to continue to perform a subpar completion technique that yields subpar well performance. Additionally, you should consider the fact that when it comes to horizontals shale development, the US Operators are armed with the highest level of intelligence, education, experience, knowledge, and technology in the industry; second to no one else in the world. Lastly, and more as an aside I think it is pretty astonishing to consider the sheer number of individuals involved in each of the independent evaluations and decisions to move to PS; it is estimated that there are approximately 359 active E&P’s in the Permian. Enough said? Apparently not, because despite all of this we still hear questions around the validity of PS today.
Sometimes people just need to see exactly how the sausage is made before they’ll eat it, so let’s step into the kitchen for the next part of this write up. There are a lot of different ways to evaluate the type of sand you want to use for your wells. I’ll start with the most simple and straight forward method that is commonly used, Crush Strength VS Reservoir Pressure. Then I will walk through a little more in-depth look at what the API measurement of crush strength really means and how it relates to well production; Well Production & Crush Strength.
Crush Strength VS Reservoir Pressure
The “crush strength” of a proppant is intended to represent the amount of closure pressure a given type of sand can withstand before “failing” or “crushing”. The American Petroleum Institute (“API”) has very detailed testing procedures for proppants laid out in its API 19C document, and these are the universally accepted standards by which we measure and report the crush strength of a proppant, or more specifically a sand in this case. The unit of measure most commonly used for crush strength is pressure per square inch (“psi”), so when you hear someone say that sand is a 10K crush, they mean that through an API testing procedure it withstood, or passed at, 10,000psi
The reservoir pressure, or more specifically closure pressure for this topic, is the measure of the maximum pressure that could be exerted on sand (or anything for that matter) pumped into the reservoir. Some will interpolate and report their approximate reservoir pressure by the amount of pressure seen during the drilling process, but without going into too much detail this is less accurate and can be somewhat subjective at times.
The more accurate/common way to measure this is by performing a Diagnostic Fracture Injection Test (“DFIT”). The term DFIT was actually coined by Halliburton, and it can go by other names depending on who you talk to, but most all are the same general procedure. The DFIT is performed after the drilling is complete and the final string of casing has been cemented in place which isolates the outside reservoir from the inside of the casing (the wellbore). At this point you will open up the cased off wellbore to the full reservoir pressure outside of the casing (shoot holes, open a sleeve, etc) and pump some set volume of fluid into the reservoir to ‘break it down’ and/or ‘initiate a fracture’, then you will measure how the pressure drops over time. The data collected in this process is analyzed in order to produce a number of reservoir characteristics, one of which is the reservoir closure pressure. The unit of measure most commonly used is again psi, and so when you hear someone say their reservoir pressure is about a 7K, this means that the maximum closure pressure you should expect on proppant being pumped into that reservoir is going to be +/-7,000psi.
Once completed, these two pressures are simply compared (reservoir pressure VS sand crush strength). If a more economic proppant is available that has a crush strength that is equal to or greater than the reservoir pressure then you can theoretically utilize it in your completion.
For example, the reservoir pressure for the most actively developed
reservoirs/counties in the Permian range from about 5K to 8K. *There are reservoirs in the Permian that are outside of this window, but they are very rare and/or much less active today. Comparatively, the crush strength of most PS range from 9K to 11K on the 100 mesh, and 6K to 8K on the 40/70. Based on this you can see why the 100 mesh PS adoption came much quicker than the 40/70 PS.
Some E&P teams operating in higher pressure reservoirs/counties took longer to get comfortable with the switch to the 40/70. However, today we really do not know any Permian Operators that have not already gotten over this hurdle or are not actively looking at using Atlas’s Permian 40/70. This is partly due to the higher crush rating (7-8K) we are consistently able to achieve with our premium open dune sand and our extensive wash process.
Well Production & Crush Strength
I think where we left off from the previous Crush Strength VS Reservoir Pressure analysis is a perfect segue into this slightly more in-depth analysis.
Two years ago when our options at Brigham Resources were mainly between NW sand and Brady Brown (or some other regional option with approximately equivalent quality/cost), the cost difference for our wells was a few dollars per ton, and therefore we were guilty of the same sin many other Operators committed – we stopped immediately after the above analysis showed our reservoir pressures were greater than the Brady sand crush strength (5K-7K) and stuck with NW for our wells. *Our southern Delaware Basin wells were in one of the highest closure stress reservoirs/counties in the Permian (+/-8K), and they were also an extra +/-60 miles from Brady TX which added cost to delivery and reduced the savings relative to using NW.
However, the choice today is vastly different than it was back then now that the quality of PS is better than Brady Brown, and the cost savings relative to NW are far more compelling. For example, the cost difference between using 100% NW sand compared to 100% PS can be as much as $65/ton, or approximately $400K to $850K per well. Now the decision of using a 7K proppant in an 8K reservoir, deserves more analysis!
As I mentioned above, there are a lot of different ways to dig into this, but the analysis I am about to walk through is a favorite of mine for venues such as this because it doesn’t get too far into the weeds and is fairly straightforward.
First let’s look at that API 19C testing. In laymen’s terms these procedures say to place 40 grams of a sand sample inside a metal cylinder, and then via a piston apply different pressures in stages to that sample of sand. At each stage the sand is removed from the cylinder and re-screened to measure how much of the individual sand grains have gotten ‘smaller’ or ‘crushed’; these smaller grains are called “fines”.
Once the total amount of fines measures to be greater than 10% of the total sand sample it is said to have failed that particular pressure stage test. For example, if a sample measured 7% fines after 6K, 9% fines after 7K, and 12% fines after 8K, that sample would be called a 7K crush sand (last passing pressure stage test overserved). At this point there should be a number of questions that come to mind; but lets focus on the following two:
1. What are these fines?
2. Would a small percentage increase in fines justify not using a sand classified as a 7K crush in an 8K reservoir?
The answer to question #1 can vary by sand size, but because 40/70 PS is arguably the only remaining cut of sand some may still have questions/doubts on, I will focus on it. First off, the nomenclature of a sand size is telling you the size of screens it would be caught between; ie – in order to call a sand a 40/70, essentially 90% of the sand sample must get caught between the 40 mesh screen and the 70 mesh screen. *Side note – the higher the mesh number the finer the screen and the smaller the sand grain.
Now during a crush test, when a 40/70 sand sample is emptied from the metal cylinder and is re-screened to measure the fines, the majority of those fines are actually caught between the 80 screen and the 140 screen. This is important to understand because this means these fines would actually fall into the size category of what 100 mesh sand is supposed to measure between. So another way to think about this would be that when that small percentage of 40/70 “crushes” it is essentially converted into 100 mesh.
So now that we understand that the fines are mostly 100 mesh question #2 actually changes to – would a small increase in the amount of 100 mesh VS 40/70 justify using or not using a different type of sand? To answer that question, we should look at the types of sands used in completions today. The shift in our industry away from coarser grain sand to finer grain sand is very well documented, and in fact it is this very shift that gave birth to the in-basin sand phenomenon in the first place.
As shown here in Figure 3, well before in-basin sand became a viable option, Operators had already been migrating to finer and finer sand and doing so without the financial incentive that in-basin offers today. *This trend has really been even stronger in the Permian than the rest of the US shale plays through 18’ & 19’, very likely due to the much more cost effective and higher quality 100 mesh available there. As an example, I would point to our own completions design progression in the southern Delaware, where we started with 5% 100 mesh & 95% 40/70 in 2014 and ended up at a 50/50 split by the time we sold to Diamondback in 2017. All the while we were achieving better well performance and higher completion efficiencies (less screen outs).
So, based on this and the continuing trend of utilizing more 100 mesh in Permian wells today it is very obvious that the answer to question #2 is, “Yes, an Operator would more than gladly utilize 40/70 PS even though a few percent more of it might end up being 100 mesh”. Furthermore, the API crush strength rating should not be viewed as a simple pass/fail test. An API 7K crush sand does not simply turn to nothing and allow the reservoir to close when it is subjected to pressures greater than 7,000 psi.
In closing, when PS was still new two years ago, there were many questions around adoption. However, those have now all been answered through the capital spending programs and adjusted development techniques of the Permian Operator community.
This shift to in-basin sand in the Permian has been absolutely transformative to our industry, and as a result the most cost-effective basin in the US just got even leaner. For those on the outside looking in, I hope this clears up some of your questions, and helps you fend off some of the erroneous rhetoric being thrown around in opposition of PS. It is understandable to be seeing and hearing the continued resistance to this industry transition because as I mentioned earlier there is so much at stake, but it should be seen purely as supposition rather than reality.
It has not been mentioned yet, but everyone should look to the times when our industry was making the move away from man-made proppants and going towards natural proppants almost a decade ago to see some of the exact same propaganda being spun.