Bakken Update: Northeast McKenzie County Wells Could Out Produce Those In Sanish And Parshall Fields

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 |  Includes: CLR, COP, EOG, HES, HK, KOG, NFX, OAS, QEP, STO, TPLM, WLL
by: Michael Filloon

Well design in the Williston Basin has changed significantly since the first horizontal wells in North Dakota and Montana. These wells typically targeted the middle Bakken using very short lateral lengths, a handful of stages and very little water and proppant. Operators have found they can use laterals in excess of 10000 feet with up to 40 stages. These wells now used 100000 barrels of water and up to 9 million pounds of proppant. Improvements have decreased depletion rates, and increased EURs. Decreased depletion will increase the cumulative production derived from fracking. If this is the case, current models may be too conservative.

When looking at Williston Basin production, it is important to remember this is a stacked play. It is focused on the middle Bakken, but the Three Forks may have more upside. The Three Forks is comprised of a series of benches. In some areas a total of four can be found. This is important as four wells could be drilled, producing a total of 16 potential targets not including the middle Bakken. The Three Forks has seen less activity, so it should have more upside. The middle Bakken has been the focus and has seen the most activity. Comparing the two is difficult, but not impossible. Middle Bakken thickness is over a hundred feet thick in some areas, but the Three Forks reaches three hundred feet. The Three Forks is also deeper. It is very likely all of these benches can be drilled from the same pad as Kodiak (NYSE:KOG) is doing in its Smokey and Polar Prospects.

Models are currently used to determine EURs. These are just estimates, and results could vary significantly. The operator, well design and geology are all independent which is why results have been inconsistent. Historical production is a better method, but there is too little data in most areas. The Sanish and Parshall fields are the only areas with enough data to model using historical production. In order to calculate EURs, depletion must be figured. Early well depletion is the most important and the curve flattens out in two to three years. After this period we can use a consistent depletion rate until production slows to a point where the well is not economic. By analyzing these wells we can see how other wells will deplete, or at least produce an estimate. This is not a perfect comparison, but should provide answers to current depletion rates.

In order to determine Table 1 provides current well designs (subscription required) by different operators. Companies have changed to longer laterals, larger chokes, increased stages, water and proppant.

Differing Well Designs By Operator In The Bakken (Table 1)

Well Operator Lateral Choke Stages H2O Proppant
21378 EOG Resources (NYSE:EOG) 6475 24/64 32 79855 6867099
22587 Statoil (NYSE:STO) 9930 128/64 39 92489 3883780
22868 Whiting Petroleum (NYSE:WLL) 8437 48/64 22 24731 1716416
21182 Kodiak Oil & Gas 9304 34/64 19 50574 1546067
21884 Continental Resources (NYSE:CLR) 9597 30/64 39 68090 3828310
21912 Hess (NYSE:HES) 9300 28/64 30 36329 1285745
22350 Oasis Petroleum (NYSE:OAS) 10020 68/64 28 66254 3507779
19738 Triangle Petroleum (NYSEMKT:TPLM) 9657 30/64 31 82504 3918293
Click to enlarge

The above table shows differences in well design. A longer lateral length provides increased surface area of the source rock to be stimulated. The choke size is very important, and a good description is found here. A tight choke allows less resource out of the well, but keeps well pressures high. Because it is more restrictive, IP rates are decreased. In general, tighter chokes are used in wells with higher gas production. It is believed this improves longer-term production, but is not as important in wells with high percentages of liquids.

Well design affects depletion. The number of feet per stage are directly correlated. The shorter the stage, the more effective the hydraulic horsepower is in stimulating the source rock. This creates better fracturing. Over time fractures start to close up under the weight of the formation unless water and proppant are used. The water pushes the proppant deep into the fractures. The proppant "props" the fractures open allowing the resource to flow. Ceramic proppant is more resilient, and does not crush as easily as sand does. Its consistent shape provides more space for crude to flow.

Table 2 is of the Bakken's best wells as of January first of 2013. I have calculated depletion starting at the average of the first 90 days. On the far right of the table, I have the total barrels of oil produced. Remember, these wells have only produced for three to four years. It will continue to produce for an estimated 30 years. It is not inconceivable some of these wells will produce a total of over 2 million barrels of oil in its life time.

The Bakken's Best Oil Producers (Table 2)

Well 90 Day

180 Day

360 Day 720 Day 1080 Day 1440 Day Bbl Oil
16059 710 748 759 834 792 743 1309064
17263 1131 1087 1123 882 744 899297
17092 799 1019 960 804 695 598 864664
17227 1654 1301 1031 891 700 573 828901
17222 1522 1280 1091 854 660 768279
17120 1538 1149 913 774 607 520 752672
17287 1128 859 845 790 623 743808
17500 958 991 917 776 637 736899
17158 953 916 741 676 597 734820
16991 1471 1127 823 684 577 489 718779
16954 1807 1336 1012 770 582 469 689021
17111 987 1035 862 726 577 479 697381
18408 849 958 949 836 711950
16885 1399 1155 978 669 523 424 645107
17416 1015 920 791 700 581 649368
17035 856 761 657 605 516 665573
17075 1285 1126 953 639 495 412 603171
17612 1393 1248 1066 732 602580
17030 1173 981 721 554 457 390 574090
17614 832 830 774 643 510 579587
Avg. 1173 1041 898 742 604 566
Depletion 11.3% 13.8% 17.4% 18.6% 6.3%
Click to enlarge

When modeling production, there are some averages I use. Wells that produce for 5.5 years are estimated to have produced 50% of its total production. In ten years or 120 months, 85% of well production occurs. These time frames can be used to predict future well production. From the 90 to 360-day IP rate we see a high rate of depletion. Years two and three have a slower, consistent depletion. In the fourth year, depletion decreases significantly.

Well design has been a big factor in producing the best middle Bakken wells. EOG has more wells than any other in the top 20. It was using the number of feet per stage, proppant per stage and water per stage that is currently used today by many of the best operators. Because of this, EOG gets more production per foot on average than any other operator in North Dakota. Table 3 provides data on wells operated by Helis. This leasehold was recently purchased by QEP Resources (NYSE:QEP) and is thought of as some of the best acreage outside Mountrail County.

Helis Results in NE McKenzie County (Table 3)

Well No. Date Lateral Choke

90 Day

180 Day

360 Day

Bbls Oil
19323 08/11 9400 26/64 1201 923 713 305463
19680 10/11 9144 26/64 785 644 482 181447
19898 10/11 9456 26/64 1033 787 577 209796
20226 12/11 8954 774 667 186457
18361 07/10 8846 965 782 560 296632
18448 09/10 9330 26/64 933 776 549 268065
18973 10/10 9078 26/64 1181 967 741 361943
19104* 05/11 9222 28/64 599 551 430 187342
20780* 06/12 9452 28/64 898 130296
21052* 12/11 9371 28/64 632 524 116697
21054 02/12 9221 28/64 868 597 114881
21331 01/12 9170 28/64 853 619 136056
21437 04/12 9392 28/64 791 117071
Avg. 886 712 579
Depletion 19.7%

18.7%

Click to enlarge

Helis has done a great job in northeast McKenzie County. Its two top wells produced more than three hundred thousand barrels of oil in the first year, and were still producing more than seven hundred barrels of oil per day. Helis has shown its acreage in Grail Field can produce 1000 MBoe wells in both the middle Bakken and Three Forks. In Table 3, I have marked wells with a * to show there were production problems.

Two of the Helis wells from Table 3 are top twenty wells using its 360-day IP rate. The Helis wells are depleting faster than the top twenty. There are two possible explanations. The first is choke size. Helis currently uses a 28/64 choke, while most operators in 2008 used a 22/64. This could be the reason for the initial decline from the 90 day to 180 day IP rates. Well number 16059 is a good example. This well didn't begin to deplete until two years of production. PetroHunt used a 5/32 choke which is tight by any standards. This is not the only reason, as well 16059 is currently the sweetest spot in North Dakota. Not only is the best well to date, it is so much better than any other that it is difficult to use as a comparison. The second possibility is the gas to oil ratio or GOR. The Helis wells are in northeast McKenzie County, which has a higher percentage of natural gas than in Mountrail County. In Table 2, the 1440-day IP rate had a depletion of 6.3%. Sometime between the 1080 and 1440 production days we see a marked decrease in depletion. This is matrix production, and the time frame used where a well falls into a lower depletion rate. QEP Resources uses 8%, for its acreage in northeast McKenzie County. In Table 4, I will use this as the standard for the remaining days to 5.5 years. It is possible this depletion data is skewed. If well 16059 is removed from the calculated depletion from the 1080-day to 1440-day IP, depletion is closer to the two years prior. I would imagine matrix production would normally start between year five and seven. This is after a hyperbolic initial decline of 87.6% from a northeast McKenzie well versus 72% in a Mountrail County well. These estimates are for middle Bakken wells, so the Helis upper Three Forks wells we could see different depletion rate. Keep all of this in mind, as these are not perfect comparisons.

Helis Well Model (Table 4)

Well

360 Day

720 Day

1080 Day

1440 Day

1800 Day

1980 Day

EUR Bbls Oil
19323 713 589 479 441 406 390 1544400
18973 741 611 497 457 420 403 1595880
19898 577 475 387 356 328 315 1247400
18361 560 461 375 345 317 304 1203840
18448 549 452 368 339 312 300 1188000
20780* 586 483 393 362 333 320 1267200
21054 485 400 326 300 276 265 1049400
21331 503 414 337 310 285 274 1085040
21437 516 425 346 318 293

281

1112760
19680 482 397 323

297

273 262 1037520
20226 542 447 364 335 308

296

1172160
21052* 426 351 286 263 242 232 918720
19104* 430 354 288 265 244 234 926640
Click to enlarge

I used the depletion rates of Helis wells with 360 days of production from Table 3 to calculate that IP rate. I did this because Helis wells have a different production mix and deplete faster than in Table 2. Of the three wells with production problems, two were Helis's worst producers. These wells were also modeled, as I decided to stay true to its total results. Table 2 data was used for the 720-day, as Helis wells have not been in production long enough to provide proper results. I used 8% as an average terminal decline starting after the third year to the 5.5 year mark. At 5.5 years an estimated 50% of production occurs, and this number is doubled. Keep in mind, all of the results from these tables are in barrels of oil only. These EUR estimates do not include natural gas or NGLs.

In summary, in some areas of the Bakken we are beginning to see enough data to produce EURs from historical production. This is important as we can now see how well design can provide better results for some operators. We can also do the same for poor results. Helis uses more water and ceramic proppant and this is why it outperforms with EURs over 1000 MBoe. It is possible northeast McKenzie County could be a better area than southwest Mountrail County. McKenzie County has very good middle Bakken wells, with an even better upper Three Forks. Additional benches also add upside. There are several ways to play northeast McKenzie. Kodiak, Newfield (NYSE:NFX), Conoco (NYSE:COP), Hess, EOG, QEP, Halcon (NYSE:HK) and Continental are all present in this area. Kodiak and Halcon are more levered to this part of the Bakken.

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. 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 shaleexperts.com. Michael Filloon is a Consultant at Fracwater Solutions L.L.C. We engage in industrial water solutions for oil and gas companies in North Dakota. This includes constructing water depots, pipelines and disposal wells. We also provide 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 other, more of my articles check out shaleexperts.com.