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On August 2nd, I covered U.S. Silica's (NYSE:SLCA) earnings miss and how that will affect its long-term prospects. This was a great buying opportunity, as the stock has been on a tear. It is up almost 50% in that short time. Current valuations are stretched and recommend letting SLCA pulling back into the $30 to $31 range before adding or starting a position. I am aware we may not get that, but the stock is too expensive at this point and perfection will be expected at next earnings. Its competitors Hi-Crush Partners (NYSE:HCLP) and Emerge Energy Services (NYSE:EMES) also have excellent prospects going into 2014. The number of rigs drilling liquids rich plays in U.S. basins looks to trend sideways to down going forward. This has led some to believe operators are cutting back, which is not the case. Developmental programs are moving forward to pad drilling as operators have large leaseholds held by production. Pad drilling saves time, which decreases costs. Batch drilling and zipper fracs reduce costs and will allow more wells to be drilled and completed without raising cap ex. The frac sand growth story has less to do with an increased number of wells drilled and more to do with an increase in proppant intensity, and longer laterals coupled with decreased drilling and completion times. Newer completion styles are creating larger fractures closer to the well bore. The greater the void, the larger the volume of proppant needed. Frac sand producers will benefit from this directly, as the larger the fractures the more sand needed to fill the void. These changes could be the start of something bigger, as early results point to much higher production per well for roughly the same cost.

I first addressed better source rock stimulation in November of 2012. EOG Resources (NYSE:EOG) pioneered fraccing shorter and wider fractures. Before this, operators were trying to create longer fracs in an attempt to garner increased shale surface area contact deeper into the shale. It was believed this would maximize recoveries, but it also created issues. Longer fractures are further from the well bore. This distance is difficult to bridge, as it has to push proppant over a greater distance. Less proppant is secured in the fractures and this increases crushing and closure of those fractures. This significantly decreases EURs. Thinner fractures also have less surface area, which creates greater pressures. These greater pressures require more resilient ceramic proppant, which is approximately 10 times more expensive than sand. Since EOG Resources creates shorter, wider fracs, it reduces that pressure allowing for the use of all sand fracs. The increased void created by this completion design requires more proppant. In some cases, these wells use up to a million pounds of sand for every 1000 feet of lateral. EOG first used this in the Eagle Ford and Permian Basin.

(click to enlarge)

The table below lists EOG's well design in the Eagle Ford prior to using it in the Bakken.

API No.IP Oil Bbls.

IP NGL Bbls.

IP GasChokeLateral Ft.Proppant Lbs.

32473 - 32477

4598-3346537-4573.2MM-2.7MM32/6454998-10MM
32636

4012

4953MM36/6445108.55MM
3256925402681.6MM40/64512611.16MM
3261722421811.1MM34/64411110.01MM
3253635794832.9MM32/6437755.82MM
350791905112673M34/6462939.53MM
349512075115688M34/64637310.09MM
3314115222201.3MM36/64648910.04MM
3314318762081.2MM36/64659910.12MM

The above wells are all in the oil window. Those results are centered in and around Gonzales County. I usually do not use 24 hour IP rates when charting well performance. In this case I did as the numbers were fantastic. I included the choke size, and it shows this production was accomplished while keeping well pressures up. The results are even better when you take lateral length into consideration. Some of these wells aren't even a mile long and are some of the best unconventional results in the U.S. to date.

(click to enlarge)

Penn Virginia (NYSE:PVA) has results from the same timeframe and general area. I have provided its results below.

API No.IP Rate Boe/dChokeLateral Ft.Proppant Lbs.
32134124716/644729
32208184718/6444533.16MM
32209118815/643913
32218119018/6439313.33MM
32217149517/6444533.48MM
32210139920/6428052.53MM
32222192116/6442004.62MM
32366180814/6434152.86MM
32376125718/6434442.81MM
32439120214/6433982.76MM
32472111514/6437032.77MM
32535100214/643153
3248096916/6432033.28MM
3362592212/6449504.24MM
33632127714/6454534.39MM
3257982712/6444532.77MM
33643103613/644453
3366283213/644201

When comparing Penn's results to EOG, keep in mind the resource mix is separated out of EOG's numbers. Penn used a tighter choke, but the size difference is not significant enough to make a material difference. The important variable is proppant amounts. EOG is dumping over 2400 lbs. of sand per foot. This is important because the more proppant, the better the perceived source rock stimulation.

In July, I reported that Whiting (NYSE:WLL) had also changed its completion design. This was significant, as other operators were beginning to use a similar, or like design. At that time, EOG had used this technology in the Eagle Ford, Permian and Bakken. Although effective in all three plays, EOG reduced its exposure to the Permian in favor of the Bakken last year. This is not to say the Bakken is superior, but EOG was worried about a falling NGL price. The decision was reinforced by its ability to rail Bakken crude and receive LLS pricing. Not only is Whiting using the same type of completion method, it has expanded to the northeast extension of Wattenberg Field. This application may be universal, as it should work in most plays. Rumor has it that EOG has also used it successfully in the PRB. Although other operators were slow to copy what EOG is doing, there is no doubt a large number will have it figured out in 2014.

(click to enlarge)

The purpose of this article is to show how this well design has implications that could significantly increase the use of frac sand in unconventional U.S. oil plays. I assert this will happen even if oil production maintains a zero growth environment, as increased usage is on a per foot basis. I have collected data on the majority of EOG's North Dakota Bakken wells using this new design, and older wells used as a comparison. This data not only covers the amount of sand used per well, but its affect on initial production rates and production per foot. In order to see the difference in completion styles, I have provided data in the table below comparing these changes and how it affected production. The series of tables below provide EOG's new design broken down by area.

Parshall Field

WellChokeLateralStagesH20ProppantIP 90IP 180IP 270
2137824/64647532798556867099793784673
2278032/64891638993169438324786770678
2123930/647873421068879023010110110821072
2209132/64102775011211410369690747694622
2270444/64106625315390010927550761
2270344/64681034933606972110748
2063348/64967249142457106908601054932
2292148/64910149139370105305671408
2140648/641029653170645136239421168
2428128/64990149136936101782601383
2376340/641246462168459124319411387
2376440/641112155143806108802591542
2268948/641099954155204111739901047

The above data is from the best producing field in North Dakota, and is almost completely controlled by EOG. The IP range is quite good, but one should not focus on this entirely. Depletion may be more important, as this percentage provides a view of longer-term production. Well 21239 was important to EOG, as it was one of the first major outperformers of this well design. This is a top 5 Bakken well as of 180 days of production. This well produced 357274 barrels of oil in the first year (360 days). Its IP 360 is 992 Bo/d. Calculating the depletion rate from the first 90 days of production to 360 days shows the advantage of this completion design. It depletes less than 10% of its production over this timeframe. Due to the decreased depletion, it raises a question as to how and when matrix production will begin. Initial well production is greater and derives for the fractures created in completion. This is when production is at its greatest, but so is depletion. Depending on the play these fractures will cease production sometime between years 3 and 5. At this time the shale matrix will start producing at a much lower production and depletion rate. Matrix production has an approximate depletion of 3% to 5% per year. The question is if depletion is curtailed through better source rock stimulation and propping, will we see matrix production further out. If so, it could change how we model EURs. Keep in mind that well 21239 is a top five well, and there are several newer wells with better 90 day IP rates. These wells had a less restrictive choke, so we could see a higher initial depletion rate.

Northeast McKenzie County

WellChokeLateralStagesH20ProppantIP 90IP 180IP 270
2168924/64440119542664639136621507
2057816/64411719492204586886709544450
2032932/648201341341749132900701
2051338/6497544911702598075801535
2433730/6497562811032697066631471
2248632/64135954715800713952857183914651245
22484TF32/641446362164652145162001497
2248534/641472764172448149258511358

Northeast McKenzie County has been a focus, and is considered the second best area in EOG's leasehold. When compared to Parshall Field, the Antelope area produces more natural gas. The Three Forks is much better than in Mountrail County, while the middle Bakken is better in Parshall. This seems to level out acreage values in comparison. Well 22486 is the best producer to date. Due to the higher gas content, a higher depletion rate is produced. Over the first 340 days of production it has produced 376287 barrels of oil. Keep in mind, this is a longer lateral at 13595 feet. This level of source rock stimulation is impressive, given the horizontal leg is much longer than a standard long lateral.

Western Williams

WellChokeLateralStagesH20ProppantIP 90IP 180IP 270
2076636/648882371033339668031598440362
2342148/649735491097539669220521392
1992796/649656481125149905670562415330
2021948/64507121556174862530246184168

Western Williams' results are much better than the old design, but the depletion rate was not as impressive. Well pressures are lower due to an interval being more shallow. This negatively impacts initial production rates, but the wells are cheaper to drill. In reality, these are still excellent numbers offering exceptional payback. IP rates are much better, and I would guess there is more upside going forward.

These numbers mean little without examples of the previous design. Geology can be different from one mile to the next, it is important to use results from the same general area. This provides a geology baseline, which provides the affects of differing well design. I have seen this done in the past, but comparing areas of differing geology provides little information on well design. The tables below provide this information.

Parshall Field Long Lateral Comparison To 21239

WellChokeLateralStagesH20ProppantIP 90IP 180IP 270
1880848/64945331293091929000204166153
1966248/64927539824685772228189188191
2119436/64956237203371705785783682578
2123930/647873421068879023010110110821072

It is difficult to produce a good comparison using long laterals given EOG didn't drill many early in Parshall Field development. Short laterals have historically produced better on a per foot basis. This is more effective because the pump trucks aren't as stressed. At this time, EOG believed it was more cost effective to drill a vertical for every 5000 feet of lateral. The two earliest results were abysmal, but well 21194 provides better data. We get much different results when comparing to short laterals much closer to well 21239.

Parshall Field Short Lateral Comparison To 21239

WellChokeLateralStagesH2OProppantIP 90IP 180IP 270
1831928/645565 209292209495899717616
1880742/64438817307242499254141114107
1931748/64349015164221645863878774
1938748/6449321512614922965163165150
2123930/647873421068879023010110110821072

Results from 2010 and earlier in Parshall Field were highly variable. Some of the wells completed here are some of the best in play, but other wells performed poorly like three of the above wells. Stage lengths were too long, creating inadequate source rock stimulation. Volumes of water and proppant were too low, which did little to prop open the fracs. This is why numbers can be misleading with respect to average production numbers in the Bakken. Although horizontal success rates in the Bakken are high (99%), there are significant differences from one well to the next. Operators are now more consistent, which has increased IP rates and EURs.

Northeast McKenzie County is well suited for pad development. QEP Resources' (NYSE:QEP) purchase of Helis' acreage in Grail and Croff fields gave an idea of its worth on a per acre basis. A large number of these wells model to EURs of 1000 MBoe. This includes both the middle Bakken and upper Three Forks. Parshall Field has had a better middle Bakken interval, but northeast McKenzie County has a much better Three Forks. Well 22486 may be the best northeast McKenzie County well to date. It could be the best Bakken well ever depending on how the well depletes. Keep in mind this lateral is over thirteen thousand feet long. EOG has completed a significant number of wells in its Antelope Prospect that have IP rates that modeling EURs above 1000 MBoe. The table below is a comparison of wells near EOG's top McKenzie County producer.

NE McKenzie County Comparison To 22486

WellChokeLateralStagesH2OProppantIP 90IP 180IP 270
22199TF20/64952539853755764801821822728
2220020/64945438689654350689619664686
2088726/64996731764844576719435403337
2088820/64954021545224172087497403375
208868/64964831752444383583587531452
2248632/64135954715800713952857183914651245

Well 22486 outperforms its old completion design by a wide margin. It is important to note that 22486 is a longer lateral, but it still significantly outperforms on a per foot basis. This is consistent with many of the new northeast McKenzie wells, as 90-day IP rates vary from 1358 Bo/d to 1839 Bo/d. It would seem this completion design functions better in wells with a higher gas resource mix. It will take time to be certain, as there is greater oil depletion in McKenzie County wells.

EOG Resources has also tested this design in western Williams. This has been an interesting area, as historical returns have not been as good. Several operators made early bets on the area, but until recently we hadn't realized western Williams' potential. On the cost side, a well here is about a million dollars less than in deeper areas of the play. Drilling times are shorter, and lower well pressures allowed the use of cheaper proppant. This savings had made the play economic, but IRRs were nowhere near those closer to Nesson. Northeast McKenzie and southwest Mountrail counties model to EURs of 750 MBoe to 1000 MBoe with older completions. Western Williams modeled to just 350 MBoe to 450 MBoe. EOG's new completions are producing much better results. Only Liberty, which was recently acquired by Kodiak (NYSE:KOG), has been able to match EOG's results. It has done this using slickwater fracs. I have provided a table below to compare EOG's 20766 with its old completion design.

W Williams County Comparison To 20766

WellChokeLateralStagesH2OProppantIP 90IP 180IP 270
1992824/64944731528814091582414313284
1947848/64929631568393883962458320268
1934836/64931826536854076401406321277
1952936/64929431523073994260435343289
2006924/64931721486493832818397291250
2076636/648882371033339668031598440362

The wells in this area are more recent, so the results are better. We can see what EOG was trying to do with its old design. It is important to note that before it changed its design, EOG was already at the top end with respect to proppant volumes. To provide a comparison of how these techniques differ and its affect on production, I have provided the table below.

Parshall Field Well Design Differences

CompletionFeet Per StageH2O Per Ft.Proppant Per Ft.90 Day Production Per Ft.270 Day Production Per Ft.90 To 270 Day Depletion
Parshall Long Old2582.11787.416.326.2%
Parshall Long New18713.6114612.636.82.6%
Parshall Short OldNA3.839714.529.931.4%

The above Parshall Field data provides key variables supporting the validity of this proppant heavy well design. Both long and short laterals were used in comparison. As you can see, EOG uses much tighter stages and increased amounts of water and proppant per foot. I used specific wells nearby for comparison. This has its advantages and disadvantages, as I believe the comparison needs to be made in like geology, so the closer the better. Most of Parshall Field was drilled early, so EOG improved on its design over time and also used mostly short laterals. It did only a few long laterals before moving to this newer design, so comparisons were limited. As you can see, it was able to tighten up stages significantly, and this seems to aid in better source rock stimulation. It also used a very high concentration of proppant and water per foot. Although the newer design seemed to be better it produced less crude per foot than the old short lateral. What improved was depletion, which is almost non-existent from 90 to 270 days of production. By manipulating the depletion curve, we will see a significant uptick in EURs.

NE McKenzie County Design Differences

CompletionFeet Per StageH2O Per Ft.Proppant Per Ft.90 Day Production Per Ft.270 Day Production Per Ft.90 To 270 Day Depletion
Old Design24496057.820.611.3%
New Design28911.6102612.224.73.4%

McKenzie County was a better area for comparison. EOG developed it later than Parshall Field, so well designs are more consistent. Its old design used decent amounts of water and proppant, so we don't see the discrepancies like Parshall. I am unsure why, but EOG used longer stages. The new design improves near-term production and more importantly depletion is still much lower. This depletion was higher than in the Parshall Field, but this has more to do with resource mix than well design.

W Williams County Design Differences

CompletionFeet Per StageH2O Per Ft.Proppant Per Ft.90 Day Production Per Foot270 Day Production Per Foot90 To 270 Day Depletion
Old Design3006.14184.47.841.5%
New Design24011.610896.124.439.5%

Western Williams did not produce the lower depletion rate seen in the first two areas. Production per foot was consistent. These well results show why EOG continually beats quarterly earnings, as analysts didn't know about these completion improvements. I have been talking about this since November of last year and finally have enough data to support the validity of the technique. It is a simple premise and this is why I believe we will see operators reproducing variations next year. Whiting has already reported its plug and perf completion with cemented liners, increased stages and perforations per stage. Whiting states this technique does not increase well costs. I think this is accomplished by using an all sand frac, which decreases exposure to much higher priced ceramic proppant. The removal of ceramic proppant seems to be more than enough to counter additional costs related to cemented liners, additional sand and stages.

There are a large number of ways to capitalize on oil and gas in the United States. Since this industry is still in its infancy, there are new ways developing and the trick is to be ahead of the curve. EOG has been an excellent company to follow as it had already identified synergies long before the competition. It was the first to rail large amounts of Bakken crude to Louisiana for LLS pricing. It also identified the importance of self sourcing sand. It made the investment early, and was able to cut costs significantly. It is also in a very good position to increase proppant usage going forward. Other operators are experimenting with this design that has little downside given higher production and lower depletion coupled with roughly the same costs. As demand increases for frac sand, realized pricing will increase and margins should expand as supply will be difficult to increase in the short term. Frac sand pricing has room to the upside as it costs just 10% of ceramic proppant. Whiting has followed suit and has successfully tested a form of this design in the Bakken and also the Niobrara. There are rumors other operators are testing this method in several other US plays. This points to what may be a universal application throughout more mature and speculative plays in the US. If this is the case, established players will not only have an advantage but also be motivated to acquire additional capacity. There are three names best positioned for this type of scenario that I listed in the beginning of this article. Of those names U.S. Silica is best positioned due to its logistical advantages. All three are decent plays on acquisition.

Source: Bakken Update: Frac Sand Pricing Could Go Parabolic As EOG Resources' Well Design Revolutionizes Unconventional Oil Production

Additional disclosure: This is not a buy recommendation. The projections or other information regarding the likelihood of various investment outcomes are hypothetical in nature, are not guaranteed for accuracy or completeness, do not reflect actual investment results, do not take into consideration commissions, margin interest and other costs, and are not guarantees of future results. All investments involve risk, losses may exceed the principal invested, and the past performance of a security, industry, sector, market or financial product does not guarantee future results or returns. For more articles like this check out our website at shaleexperts.com. Fracwater Solutions L.L.C. engages in industrial water solutions for oil and gas companies in North Dakota. This includes constructing water depots, pipelines and disposal wells. It also provides contracting services for all types of construction at well sites. Other services include soil remediation. Please contact me via email if you are interested in working with us. For more of my articles and other pertinent information on the oil and gas sector, go to shaleexperts.com.