Bakken Update: 5 NE McKenzie County Wells With Revenues Over $17 Million In Under 2 Years

 |  Includes: CLR, EOG, HK, KOG, MRO, QEP
by: Michael Filloon

This is the fourth in a series of articles focusing on well results in the Bakken. I initially started in western Williams County. This area is being developed aggressively and better well designs have increased IP rates and EURs. EOG Resources (NYSE:EOG) is outperforming here, but in my accumulation of data, I found Liberty Resources' wells were also outperforming. This should help to drive Kodiak's (NYSE:KOG) earnings in 2013. This is why well data is so important, as I was initially bearish on the transaction. Once I figured the production rates, I realized why Kodiak made this deal. Liberty's well results may be the best in the area, as its 180-Day IP rates rival EOG's.

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The Liberty data is an example of why I decided to do this series. Well results are the basis for this business. Those that outperform like Kodiak and EOG will reward shareholders. Others that do not, like Samson (NYSEMKT:SSN) will watch its stock price go near zero. The data I am targeting not only aids in finding a good investment, it also helps clear up misconceptions in unconventional liquids rich plays in the United States. There are three Bakken misconceptions I believe are false, and can prove so by calculating individual variables of well design and production. The first misconception is the Bakken's best areas have already been drilled. This is based on a generalization of well results. Bakken bears take all of the wells drilled in North Dakota and combine those results. If all of the wells ever drilled are used, we see lower IP rates. The first Bakken wells had poor well design. This includes a very low number of stages, which did not stimulate the source rock enough to create an ample amount of fractures. These wells used small volumes of water and amounts of proppant. The water pushes the proppant into the fractures and props it open. Limited amounts of water means the proppant will not enter deep enough of the formation. This means less resource can flow into the well. Type of proppant was also an issue. In deeper parts of the play there are higher pressures. Sand crushes under the weight of the formation, closing off resource to the well. This is why many operators use ceramic proppant or ceramic coated sand. Early wells using just sand, will produce fairly well initially with huge depletion rate as the fractures crushed the sand and closed the formation. The first misconception is enforced further based on EOG's results in Parshall Field. This operator and field are the home of the majority of top 20 historical Bakken producers. Bakken bears compare these excellent results to current results to show the best wells have already been completed. These results have to do with geology and well design. The Parshall Field is unique as it is influenced by migration and trapping mechanisms. This geology is unique, but there are other very good areas. This includes northeast McKenzie County. This area's middle Bakken is not as good as Parshall Field, but its Three Forks is much better. If we compare these two areas by all targeted source rock, we may find Parshall Field comes up short. Parshall Field results also have to do with well design. EOG was far ahead of its competitors. Its shorter laterals used in concert with tighter stages and large amounts of water and proppant is a better design than many operators use today. The data I am compiling on production in the Bakken and Three Forks will prove this misconception incorrect. There are large areas where the Three Forks is 300 feet thick, and could produce much better than the middle Bakken.

The second misconception is Bakken wells deplete quickly and only produced a few years. Some operators have much higher depletion rates. I already discussed how inadequate amounts and type of proppant can cause this, but the type of choke can also affect depletion. The choke is used to restrict production and keep well pressures high. Some companies like Brigham open up the well with a wide choke. This allows a large amount of resource to be produced in a very short time. This maximizes initial production, but also increases depletion. The second misconception is enforced by a lack of understanding of how an unconventional well produces. There are two phases of production. The first from the induced fractures. This provides a large amount of production followed by significant depletion. Some believe this depletion (hyperbolic decline) is maintained through the life of the well, which is incorrect. The hyperbolic initial decline occurs over the first 3 to 6 years of production. This depletion rate varies from 70% to 90% depending on area (and many other factors). After these fractures stop producing, the well will produce from the matrix. This is where the mistake is made in modeling wells. This depletion rate varies from 5% to 8% over the next 30 to 40 years of production. Bakken bears use hyperbolic decline much longer, depleting production until it becomes a stripper well. I cannot stress enough that 24-hour IP rates mean little. We do not even begin to establish how good a well is until at least 90-Days of production. My data shows different depletion rates by operator and area. This shows that well design has slowed depletion, and wells are producing more initially and later in well life.

The third misconception is total Bakken well production. By taking all of the wells and creating an average from the beginning of Bakken development to the present, we see a very low average. Bakken bears use this number to show the majority of Bakken wells have production much lower than operator estimates. There are several problems with this method. The first Bakken wells had poor well design. Many of the first wells had lateral lengths below 5000 feet, and very few stages. Inadequate amounts of water and proppant also hurt production. Operators had little experience, and saw major issues in early development. Some wells produced only a few thousand barrels of oil, based on poor operations. Wells completed in 2006 to 2008 have no bearing on how the Bakken produces today. Using those results only skews current data. Production needs to be broken down by year and foot to provide a better view of how today's wells are producing. Many of the older wells were completed with small amounts of water and proppant. As I stated earlier, these wells used sand as proppant and this did not effectively prop open the fractures. In some cases, operator error missed the source rock and produced little to nothing. My data focuses on wells completed in 2011 and 2012. It gives a better idea of where we are now, and how that equates to success in the Bakken.

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Northeast McKenzie County is one of the best producing areas of the Bakken. This article focuses on Grail and Antelope fields. These wells are farther south of my last article. I chose Grail to analyze Helis' well results. This field has the best producing Three Forks wells in North Dakota and Montana. QEP Resources (NYSE:QEP) paid top dollar for this acreage, and insight into unlocking resource in this area. Helis' operated wells in Grail out performed other wells in the area, but more important it depletes much slower. QEP now owns these wells, which I have provided date in the table below.

QEP Well Results in Grail Field
Well Lateral Ft. Stages Water Bbls. Proppant Lbs. 30-Day IP Bo/d 90-Day IP Bo/d 180-Day IP Bo/d
19680TF 9144 28 76942 2674660 1138 774 644
19898TF 9452 27 78608 3338206 1492 1033 787
21052TF 8929 28 79799 3109015 757 632 504
21054TF 9113 28 78796 3144880 1056 868 597
21437TF 9171 30 89653 3594290 1055 791 682
21465TF 9208 29 79012 3532991 1311 1029 919
20780TF 9128 28 78632 3071795 1194 977 787
21456TF 9405 31 84655 3591030 1404 953 735
22820TF 9259 30 81044 3656740 1071 839 656
Avg. 9201 29 80793 3301511 1164 877 701
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None of the above wells were drilled and completed by QEP, as Helis was the operator. I focused on wells that were brought online between 9/2011 to 7/2012. This well design is very good. It uses a little over 300 foot stages with approximately 80000 Bbls of water and 3 million pounds of ceramic proppant. Superior well design coupled with large amounts of ceramic proppant have produced very good and consistent results. Most of these wells have EURs of 1000+ MBoe. Grail has set the standard in northeast McKenzie. We will compare it to EOG Resources' Antelope Extension Prospect.

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To the north and east of Grail is Antelope Field. This is on the eastern most edge of McKenzie County. Antelope Field terminates at the lake, which is at its border with Mountrail County. There is significant activity here. This area was the focus of EOG's additional land grab in North Dakota. It recently began adding acreage, as its Bakken results have had better economics than its other plays, such as the Wolfcamp.

2011-2012 EOG Well Results In Antelope Field
Well Lateral Ft. Stages Water Bbls. Proppant Lbs. 30-Day IP Bo/d 90-Day IP Bo/d 180-Day IP Bo/d
20307 3541 13 25563 1818911 464 323 253
22505TF 8611 38 65208 4215829 571 548 458
20550 8769 37 66916 4297760 943 804 678
19790TF 8891 31 82371 3838916 911 769 641
20602 8463 44 64748 4095071 1296 1089 798
Avg. 7655 33 60961 3653297 837 707 566
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EOG has had better luck with the middle Bakken, but the Three Forks is also performing well. It hasn't used its proppant heavy well design in this field the large amounts of proppant as seen in Parshall and western Williams County. I believe this area has 30% upside if and when this is applied in Antelope Field. EOG is still outperforming on a production basis, as its well design is superior to other operators in the area. The above data shows the importance of shorter stages. The last well on this list is quite good. It is the only well on this list with stages shorter than 200 feet. This seems to be most effective length. EOG uses ample amounts of water, but continues to use large amounts of proppant. Source rock stimulation is EOG's focal point. Keep in mind, it matters little how much water and proppant you use if there are no fractures to prop open. I would guess these well results will get much better for EOG over the rest of 2013.

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From a data standpoint, Antelope Field is excellent. This field has seen significant development by several different operators. Continental (NYSE:CLR) has been developing its leasehold in this field.

2011-2012 Continental Well Results In Antelope Field
Well Lateral Ft. Stages Water Bbls. Proppant Lbs. 30-Day IP Bo/d 90-Day IP Bo/d 180-Day IP Bo/d
20623 5043 15 25820 1422043 396 306 237
21152 5177 15 26545 1258927 471 335 268
19232TF 9526 30 53959 2890910 984 765 606
20674 10556 40 85076 3851922 688 665 574
21151 4946 15 28348 1258976 584 391 291
Avg. 7050 23 43950 2136556 625 492 395
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Continental continues to use a well design with minimal amounts of water and proppant. It is beginning to tighten stages as seen in well 20674. It also is increasing the amounts of water and proppant per foot. The best well of this group didn't have a superior well design, but it targeted the upper Three Forks. Well 20674 should have outperformed the other middle Bakken wells, but shorter laterals continue to see better source rock stimulation. Other than the one well, the design is inadequate when compared to other better performing operators. Keep in mind, Continental has some of the lowest well costs in the Bakken. With costs heading lower, we could see Continental add stages, water and proppant.

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Marathon (NYSE:MRO) is also in Antelope Field. It had several completions, but all were in 2011. I added 2012 completions from Four Bears and Reunion Bay fields to provide later well results. Both are adjacent to Antelope Field.

2011-2012 Marathon Well Results In Antelope, Four Bears, and Reunion Bay Fields
Well Lateral Ft. Stages Water Bbls. Proppant Lbs. 30-Day IP Bo/d 90-Day IP Bo/d 180-Day IP Bo/d
19321 9646 20 25317 2750160 683 696 674
19838 9570 20 25104 2777699 515 366 288
19839 9421 20 23118 2647800 667 540 437
21478 9518 30 16449 2607197 747 552 422
21479TF 9059 30 17444 2223946 690 548 432
21199TF 9112 30 24810 2352689 733 523 407
23799 9490 30 20566 2516999 709 559 438
Avg. 9402 26 21830 2553784 678 541 443
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Marathon uses low volumes of water. It also uses average amounts of proppant. It is possible, given the volumes of water used, Marathon may be using Schlumberger's (NYSE:SLB) HiWAY Flow-Channel Hydraulic Fracturing Technique. This requires less water and proppant. Marathon's results have been mediocre, and it underperforms in this field.

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When Halcon (NYSE:HK) purchased Petro-Hunt's acreage, it inherited wells in Antelope Field. Petro-Hunt uses a completely different well design in northeast McKenzie County. In western Williams, we saw Petro-Hunt struggle with results when compared to other operators.

2011-2012 Halcon Well Results In Antelope Field
Well Lateral Ft. Stages Water Bbls. Proppant Lbs. 30-Day IP Bo/d 90-Day IP Bo/d 180-Day IP Bo/d
18426TF 9643 27 79515 3172504 786 656 531
20088TF 9877 29 80500 2736620 742 778 729
20328 9705 26 71295 2675830 1238 942 776
20567 9290 24 71962 3203737 664 603 515
23550 9133 26 71516 2625720 582 506
Avg. 9530 26 74958 2882882 802 697 638
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Petro-Hunt did a great job of drilling and completing wells in Antelope Field. It uses a more complex well design than in other areas. Its focus is this area when compared to its western Williams County leasehold. Halcon has managed to improve its results in western Williams. I would guess it will do the same in Antelope Field. It seems to have found a balance with average stage length, average proppant amounts and large volumes of water.

Well Results By Operator Per Foot
Co. Feet/ Stage Water/ Foot Proppant/ Foot 180-Day Production/ Foot
QEP 317 8.8 359 13.7
EOG 232 8.0 477 13.3
CLR 307 6.2 303 10.1
MRO 362 2.3 272 8.5
HK 367 7.9 303 12.1
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The Helis acreage now operated by QEP is a top notch prospect. As expected, EOG's wells are a close second with Petro-Hunt's wells now operated by Halcon third. QEP's acreage may be the best, as it still outperformed EOG's shorter stages, and more proppant. QEP's wells were completed with 100% ceramic proppant, and this probably contributed to the better results. Halcon's acreage may have more upside. It is doing several things to improve production and reduce costs. It is implementing batch drilling efficiencies. Halcon believes it can make further drilling improvements such as optimized motor/bit combinations and drilling with back-pressure. If Halcon tightens up the stages and increases proppant per foot, we will see even better production. Continental's results weren't bad, but it needs to better its design. Its results are mostly middle Bakken. We may see a better average as it completes more Three Forks wells. Marathon's production results were well below the other operators. This is not surprising given its well design. Marathon's Three Forks wells weren't better than its middle Bakken. The upper Three Forks should be better here, and seems to be as it is outperforming with much less de-risking.

Although these wells may never break the top 20, it still has very good economics. QEP's Grail Field acreage has been more consistent. QEP's best well was much better than any other operator's. Below are the best wells by operator.

Well Economics For Operators In Grail/Antelope Field Area
Well Co. Total Oil Bbls. Oil Revenues Total Gas Mcf Gas Revenues Days Total Revenues
21465TF QEP 252102 $22689180 248716 $994864 371 $23684044
20602 EOG 205435 $18489150 323979 $1295916 293 $19785066
19232TF CLR 187974 $16917660 218646 $874584 478 $17792244
19321 MRO 303374 $27303660 363373 $1453492 636 $28757152
20328 HK 249549 $22459410 307390 $1229560 445 $23688970
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In the above table, I am using $90/Bbl. Bakken crude pricing. I am also using $4/Mcf of gas. Bakken operators generally receive a much higher price for this, as approximately 50% of its Mcf is NGLs. In previous articles on this subject, outperforming wells were completed later in 2012. The problem with this time frame is limited data. Only one well on this list had less than one year of production, and it had already produced approximately $20 million in revenues. The table above is focused on the best wells in Grail and Antelope fields. To provide the economics of poor producing wells, I calculated the total crude revenues of Marathon's lowest producing well. Well 19838 had a 180-Day IP rate of 288 Bo/d. In 618 days, this well produced crude revenues of $10287810. It is conceivable this underperforming well will pay back in less than two years.

In summary, QEP bought some of the best acreage in the Bakken. The Three Forks in concert with the middle Bakken provides an excellent area for pad drilling. The Three Forks is already showing signs of better production, with less de-risking. Operators are still getting comfortable with the formation, and should have an increased margin for improvement. EOG has managed to outperform without its new well design. I estimate 30% upside when this is used. Halcon looks to have made a nice acquisition given Petro-Hunt's results. Continental Antelope Prospect would benefit from additional Three Forks wells. I believe this will improve its IP rates. Marathon's wells had lower production numbers. I would guess it will continue to better its well design. It would almost have to, as its results have been sub-par. Most important is the revenues generated. Every operator was able to at least produce $17 million. With well costs between $8 and $10 million, the return on investment is excellent.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

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 in 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 my website at 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. More of my articles and other pertinent information on the oil and gas sector, go to