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Michael Filloon, Split Rock (379 clicks)
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In the first and second parts of this series I provided an opposing viewpoint to an article published on theoildrum.com. In my most recent article, I produced rough estimates of Bakken well production. I was able to show the Williston Basin produces significantly different data from one county to the next. In the third part of this series I will use specific well production data to show the Red Queen article provides a skewed representation of the Bakken.

I have compiled data on 40 wells in Mountrail County, and have found very good results. These wells were located in four different fields around the Sanish Field. I did not include any Sanish Field results as this field was one of the focal points in the "Red Queen" article. Since well completions are continually evolving and producing more resource, I only used wells completed in 2011 with a years worth of production. I included specific completion data to show why certain wells performed better than others.

One variable the "Red Queen" article did not account for was lateral length. EOG Resources (EOG) and Enerplus (ERF) have done a large number of short laterals. These companies, and others continue to use this approach. Short laterals are generally around 5000 feet versus long laterals which are approximately 10000 feet. As one could guess, short laterals produce about half the production of a long lateral. Long laterals have contact with a larger area of the formation. The number of stages are also important. The higher the number of stages used the better the production. As a well increases the number of stages, each stage will be in a shorter length. Shorter stages produce better stimulation as the hydraulic horsepower of the pump trucks produces greater pressure. Increased volumes of water and proppant also provide for better production. When the formation is fracced the water pushes the proppant into the fractures. This proppant "props" open the fractures allowing for more oil to flow into the lateral. The better the proppant the longer the fractures are held open. Sand does not hold open these fractures as long and this shuts off oil flow sooner. Keeping this in mind, each operator calculates well cost and offsets this with what it believes production increases will be. We are seeing more capital used to drill and complete wells, as the increased revenue from production more than offsets these costs.

In the table below I have listed 2011 wells in western Mountrail County. This is a very good area, but the results I found were better than I originally expected.

Alger, Manitou, Alkali Creek, Van Hook Field Production
Well Operator Days 120 Days 360 Days Lateral Stages Choke Water Proppant Ceramic
17355 (STO) 459 92387 173321 10040 36 167/64 3673705 4021580 2454060
19513 STO 465 99854 187436 10053 38 181/64 3570032 4106600 2514440
19764 STO 434 76656 139436 9413 38 179/64 3660805 3854880 2322900
18881 STO 437 49881 93771 9337
19861 STO 390 64697 119485 8978 30 160/64 2965925 3641760 2227380
18760 STO 442 73449 129982 9600 37 118/64 3274966 3671960 2247680
19793 EOG 464 45109 95067 11024 31 15/64 2683157 3066787 Sand
19794 EOG 429 40036 75944 12745 25 24/64 2413332 3421985 Sand
19679 EOG 430 52393 97955 10546 31 32/64 2327977 3310648 Sand
19767 EOG 428 41468 79863 10253 32 28/64 3031500 3400000
19722 EOG 517 33265 66229 5861 15 32/64 1357768 2368012 Sand
19560 EOG 484 46246 92351 6283 15 24/64 1097833 2565070 Sand
19985 Hess (HES) 383 69601 116202 9341

32/64

19421 HES 522 15047 26647 6163 22 24/64 1323884 819014 Sand
19403 Continental Resources (CLR) 403 47870 89381 8749 24 20/64 1985482 2309500 649200 TF
19339 Exxon Mobil (XOM) 409 24619 47727 10198 18 20/64 2394068 2757849 Sand MB
19402 CLR 400 48132 96097 9627 24 18/64 2093498 2312560 645900 TF
19568 HES 408 53743 86449 9297 22 22/64 1738103 1097939 Sand MB
19569 HES 399 44107 83614 9076 22 22/64 2070923 1931448 1100137 TF
19076 HES 401 93547 171671 9818 38 28/64 3620729 3986800 1900040 MB
19075 HES 407 40416 72546 8276 22 48/64 998332 1362180 651300 TF
19078 HES 377 66343 127069 9622 32/64
19079 HES 374 91169 159237 10262 21 32/64 3548446 3991480 1918820 MB
17661 OAS 397 46465 98879 9580 44/64 3501791 4584289 2767526 MB
19592 HES 448 38312 85494 5726 28/64
19649 HES 597 49716 92646 9075 22/64
18737 WPX (WPX) 565 57401 112839 9096 20 20/64 1464924 1564468 MB
18735 WPX 497 89970 194661 9286 25 24/64 5543560 2822970 MB
18963 WPX 487 74446 133740 9201 24 18/64 2353261 2725817 MB
18794 WPX 463 99948 189891 9219 16/64
19181 Marathon (MRO) 439 62867 131614 9250 20 14/64 942603 2440600 MB
20037 EOG 418 71413 148838 14024 31 38/64 2952896 5790703 Sand MB
19720 EOG 481 54278 117207 12221 25 24/64 1919262 3066787 MB
19721 EOG 512 63044 157122 12650 31 38/64 2670429 4975678 Sand MB
19919 EOG 399 85913 204751 9968 31 30/64 2077545 3988933 Sand MB
18828 EOG 535 84873 171216 9737 20 38/64 1955984 3022626 Sand MB
20346 Slawson 430 56616 110108 4364 19 11/64 946000 1870020 MB
20551 Slawson 390 72183 161167 9906 41 12/64 2064000 3886020 MB
18872 Slawson 460 41424 94679 4432 19 13/64 871825 1870020 MB
19368 Slawson 372 42166 137723 9208 40 48/64 2167587 3971555 MB
Average 60027 119251 9288

This research covers a large area. The wells used are as far apart as 43 miles. Of these forty wells, only three wells produced less that the 70000 barrels of oil in the first twelve months. Of these three, one well was a short lateral that still produced more than 66000 barrels of oil in that time frame. This is important as the "Red Queen" article used that annual production estimate to model the low end of the Bakken production curve. Eleven wells produced more than 150000 barrels of oil, and that does not include the short laterals that produced more than 75000 barrels. Over one quarter of these wells produced at least 33% more barrels of oil than the highest point of Mr. Likvern's curve when differences for lateral length are accounted for.

The Red Queen article uses Mr. Likvern's annual estimated production to define how it will grow over 29.5 year well life. Here are his estimated ultimate recoveries or EURs based on those annual production numbers.

Cumulative Barrels of Oil Per Well
Annual Production EUR
70000 Barrels of Oil 240000 Barrels of Oil
85000 Barrels of Oil 290000 Barrels of Oil
100000 Barrels of Oil 340000 Barrels of Oil

In summary, those familiar with North Dakota production know these EURs are low. In fact, it is lower than most if not all estimates given by oil producers in North Dakota. The "Red Queen" production model is too general to be useful. It provides little in differences to area or oil producers. Kodiak (KOG) continually has better well results than its competition. This is why Kodiak is comforable with some of the highest well costs in the basin. Western Mountrail is different from western Williams County. The middle Bakken in Mountrail is not only thicker, but it is deeper as well. Well pressures are greater in Mountrail which produces much larger initial production rates. These rates deplete faster, but still produce significantly greater resource. Well costs are on average $2 million higher in this area than other more shallow locations. Western Williams County has lower IP rates, but deplete slower. This is why we see 24 hour IP rates north of 4000 Boe/d in Mountrail County produce EURs of 900 to 1000 MBoe. Western Williams wells produce 24 hour IP rates south of 1000 Boe/d, but still have EURs of 450 MBoe. It is important to break down the Bakken into areas, to properly judge economics.

Source: Bakken Update: The Red Queen Is Just A Fairy Tale Part III