Enno Peters
This is an older blog post, you will find one on more recent data here
This interactive presentation contains the latest oil & gas production data from 81,656 horizontal wells in 10 US states, through November last year. Cumulative oil and gas production from these wells reached 7.9 Gbo and 82.6 Tcf.
Excluding West Virginia (which will report production for the full 2017 in a couple of months), horizontal wells in these states produced more than 4.5 million bo/d, and 45 Bcf/d in November 2017, setting new records for both (after revision data is in).
As especially initial well performance has improved in most of the basins, the share of production from top producers is increasing. You can see this for both oil & gas, if you set the ‘Show production by’ selection to ‘Production level’. E.g. more than 1/3rd of oil production in November came from just ~2,200 wells that produced more than 400 bo/d each.
In the ‘Well quality’ tab production profiles for all these wells (oily basins are pre-selected) are plotted, with wells grouped by the year in which production started. As the bottom graph shows, well productivity was up each year since 2012, with especially a major jump in 2016. Longer term improvements are still less apparent, especially when compared with the early Bakken wells from 2008-2010. You can use the ‘Selection’ filters to view these profiles for more specific regions/operators or even single wells.
The ‘Well status’ tab gives an overview of the status of all these wells. The inflection point in 2016 is visible here, as drilling & completion activity started to ramp up again.
The last overview (‘Top operators’) shows the 5 largest oil & gas operators in these states, based on operated production from horizontal wells. EOG (oil) and Chesapeake (natural gas) are the clear leaders.
The ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows the relationship between cumulative production, and production rates, over time. I’ve preselected the major oil basins, and the wells are grouped by the year in which production started.
Here the impact that these year-on-year productivity improvements have had on the trajectory towards ultimate recovery are even more clearly visible. If you change the ‘Show wells by’ selection to ‘Quarter of first flow’, wells will be grouped by the quarter in which production started, and you can see that since Q4 2016 no further improvements are yet visible, although the number of new wells did increase.
If you want to analyze the improvements in well productivity over time in more detail, I recommend the 5th tab (‘Productivity over time’), where you can select based on how many months (e.g. 24 months cumulative production) this metric should be displayed.
On Thursday I will have a new post on North Dakota, followed by an update on Ohio & Pennsylvania early next week.
You can follow me on twitter here.
Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below.
- FracFocus.org
- Colorado Oil & Gas Conservation Commission
- Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories.
- Montana Board of Oil and Gas
- New Mexico Oil Conservation Commission
- North Dakota Department of Natural Resources
- Ohio Department of Natural Resources
- Pennsylvania Department of Environmental Protection
- Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data.
- West Virginia Department of Environmental Protection
- West Virginia Geological & Economical Survey
- Wyoming Oil & Gas Conservation Commission
====BRIEF MANUAL====
The above presentations have many interactive features:
- You can click through the blocks on the top to see the slides.
- Each slide has filters that can be set, e.g. to select individual or groups of operators. You can first click “all” to deselect all items. You have to click the “apply” button at the bottom to enforce the changes. After that, click anywhere on the presentation.
- Tooltips are shown by just hovering the mouse over parts of the presentation.
- You can move the map around, and zoom in/out.
- By clicking on the legend you can highlight selected items.
- Note that filters have to be set for each tab separately.
- The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.
- If you have any questions on how to use the interactivity, or how to analyze specific questions, please don’t hesitate to ask.
News, trends and data for the US upstream industry
Novi Energy Newsletter
10 Comments
Nobody wants to talk about shales oil dirty secret. The decline rates on infill drilling is amazing. It the three infill drilling data I have the first year ip decline rate average 85 percent and the second year is tracking at greater that a 50 percent decline.
The Whiting twin valley is a 28 well 4 section test. Whiting drilled 14 wells per two sections and the decline rate is stunning.
Production Month Days Day rate Month decline Days on production
Jan-18 108,179 864 125.21 (0.10) 28
Dec-17 118,213 851 138.91 (0.07) 28
Nov-17 122,778 819 149.91 (0.07) 28
Oct-17 132,619 824 160.95 (0.06) 28
Sep-17 143,642 838 171.41 (0.12) 28
Aug-17 164,012 843 194.56 (0.08) 28
Jul-17 172,452 815 211.60 (0.10) 28
Jun-17 195,253 827 236.10 (0.13) 28
May-17 232,294 856 271.37 (0.17) 28
Apr-17 267,780 823 325.37 (0.14) 28
Mar-17 328,038 865 379.23 (0.11) 28
Feb-17 328,067 772 424.96 (0.11) 28
Jan-17 411,022 862 476.82 (0.21) 28
Dec-16 515,390 851 605.63 (0.18) 28
Nov-16 608,377 824 738.32 (0.29) 28
Oct-16 636,345 610 1,043.19 (0.08) 28
Sep-16 101,919 90 1,132.43 – 21
Aug-16 – – – (1.00) 0
Jul-16 39,801 148 268.93 (0.03) 15
Jun-16 123,701 446 277.36 (0.15) 15
May-16 116,059 354 327.85 0.03 15
Apr-16 140,356 439 319.72 (0.17) 15
Mar-16 164,995 430 383.71 (0.14) 15
Feb-16 169,606 378 448.69 (0.09) 15
Jan-16 227,491 463 491.34 (0.20) 15
Dec-15 273,451 446 613.12 0.00 15
Nov-15 177,907 291 611.36 0.62 15
Oct-15 103,332 273 378.51 0.26 15
Sep-15 60,606 201 301.52 0.04 11
Aug-15 67,274 233 288.73 (0.01) 11
Jul-15 82,883 285 290.82 (0.17) 10
Jun-15 103,200 293 352.22 (0.07) 11
May-15 119,402 316 377.85 (0.20) 11
Apr-15 133,925 285 469.91 (0.11) 10
Mar-15 168,131 318 528.71 (0.10) 11
Feb-15 181,575 308 589.53 (0.10) 11
Jan-15 223,742 341 656.13 (0.07) 11
Dec-14 239,399 341 702.05 (0.07) 11
Nov-14 245,881 325 756.56 (0.18) 11
Oct-14 257,568 278 926.50 0.79 11
Sep-14 58,400 113 516.81 0.22 5
Aug-14 76,032 180 422.40 (0.14) 8
Jul-14 122,300 248 493.15 (0.40) 8
Jun-14 142,098 174 816.66 2.37 8
May-14 38,031 157 242.24 (0.12) 6
Apr-14 49,735 180 276.31 (0.13) 6
Mar-14 57,595 182 316.46 (0.09) 6
Feb-14 50,030 144 347.43 (0.18) 6
Jan-14 49,843 117 426.01 0.11 6
Dec-13 57,066 149 382.99 0.00 6
Nov-13 68,776 180 382.09 (0.10) 6
Oct-13 78,029 184 424.07 (0.14) 6
Sep-13 84,378 171 493.44 (0.21) 6
Aug-13 99,098 158 627.20 (0.22) 6
Jul-13 149,627 185 808.79 (0.14) 6
Jun-13 157,940 168 940.12 1.67 6
May-13 31,353 89 352.28 (0.08) 3
Mar-13 30,798 80 384.98 (0.15) 3
Feb-13 42,052 93 452.17 (0.30) 3
Jan-13 43,535 67 649.78 (0.16) 3
Dec-12 72,055 93 774.78 (0.16) 3
Nov-12 28,523 31 920.10 0.73 3
Oct-12 15,966 30 532.20 1.18 1
Sep-12 3,656 15 243.73 (0.37) 1
Aug-12 11,646 30 388.20 (0.15) 1
Jul-12 10,510 23 456.96 0.01 1
Jun-12 14,007 31 451.84 (0.13) 1
May-12 15,501 30 516.70 (0.06) 1
Apr-12 17,008 31 548.65 (0.07) 1
Mar-12 17,731 30 591.03 (0.15) 1
Feb-12 21,492 31 693.29 (0.11) 1
Jan-12 22,545 29 777.41 (0.11) 1
Dec-11 27,145 31 875.65 (0.22) 1
Nov-11 35,016 31 1,129.55 (0.23) 1
Oct-11 44,240 30 1,474.67 0.12 1
Sep-11 26,264 20 1,313.20 – 1
Aug-11 – – 0
Jul-11 – – 0
Jun-11 – – 0
Total 9,876,686 23,961
I couldn’t get the pdf to work so I just downloaded the raw data.
Also the last column of the day should read Wells in the 4 sections not Days on production.
Oct 2016 was the peak month with 636,345 barrels of oil producing and 15 months later the same 28 wells only produced 108,179.
OCT 2016 Day Rate: 20,527 Bopd
Jan 2018 Day rate: 3,489 Bopd
15 month decline rate of 83 percent.
Wow is all I can say.
Average well only produces 124 Bopd in month 15.
After month 36 these wells will be stripper wells at the rate they are declining.
Also if we assume the average well is 8 million dollars Whiting spent 224 million to develop these sections. I doubt these drilling pilot will ever make the full cycle returns they are spewing to investors.
I have more of the dense infill drilling data and they all look the same.
Higher than average decline rates and rapid depletion of the field.
This should explain what is happening above
https://digitalcommons.mtech.edu/cgi/viewcontent.cgi?article=1028&context=grad_rsch
https://digitalcommons.mtech.edu/cgi/viewcontent.cgi?article=1028&context=grad_rsch
I forgot to include the link
Reviewing the reservoir engineering drive mechanisms for the Bakken and the Permian, the two basins have very contrasting characteristics which will determine their long term performance and ultimate development strategy:
BAKKEN – This resevoir appears to be operating under depletion drive, with basin-wide GOR steadily rising to almost triple the initial solution GOR. Annual new well starts are consistently ramping up GOR faster every year, suggesting that average basin pressure is dropping. Even though wells are showing higher initial productivity, the higher rate of GOR increase will offset this benefit and result in steeper declines over the 12-36 month period.
The rate vs cum charts demonstrate that despite improvements in fraccing effectiveness (and presumably associated increases in completions cost), average recoverable reserves per well (over 10 years’ production life) stubbornly refuse to exceed 250k bbl. Fraccing is proving to be a highly effective acceleration tool, but there is little evidence at the basin scale that it will materially increase mean ultimate recovery per well. The premium that shale drillers are willing to pay for ever greater fraccing effectiveness will therefore be limited by nature’s forces, unless drainage area (ie Hz drain length) is significantly extended.
Bakken water cut is increasing gradually as the aquifer continues to flow towards the producers, and will likely continue to imbibe at the same steady pace. Wells are less likely to suffer from water influx related production constraints than by solution gas expansion, and water disposal issues will likely be less of a problem than delivering the ever increasing associated gas production to market. This will require an extensive network of gas pipelines to gather the associated gas, or novel techniques such as remote wellsite CNG/LNG store-and-ship solutions if flaring or venting is to be avoided.
Basin wide GOR is increasing to 2 Bcf/d, and oil production is around 1.1 million bopd. At notional commodity prices of $65/bbl and $3/Mcf, this corresponds to annual sales revenues of Oil: $26.5 Billion, Natural Gas: $2.2 Bn, promoting natural gas to represent 7.7% of potential resource value. The value share of Bakken gas will only increase over time as GOR will inevitably continue to rise along its now well established trajectory.
PERMIAN – The Permian reservoirs contain a lighter oil, likely lower viscosity than Bakken, which eases its ability to flow through tight rock. Being a far larger and less mature basin than the Permian (production only really started taking off in 2013), the basin’s recovery factor is still relatively low as production continues to ramp up YoY.
In contrast to the Bakken, high rates of formation water production are expected to contribute towards Permian wells depletion, and represents a basin wide challenge as cumulative well count and accompanying oil production rate increases. Permian (Tx+NM) production rates of 1.58 million bopd are associated with over 4.35 million barrels per day of saline water than must be piped, shipped, injected, evaporated, or otherwise disposed of. This is roughly equivalent to 60% of the fresh water volume supplied each day to the 2.3 million residents of the City of Houston, a truly vast amount of water for a non-utility industry to treat.
I predict that infrastructure scale issues (water disposal, frac sand supply, transportation limits, associated gas capture and distribution) will likely constrain peak Permian production even at current prices. Even if drilling rig capacity and investor willingness were to achieve continued production growth rates of +0.3 million b/d per year, the corresponding water disposal challenges of +0.75 million b/d per year and gas distribution of +1 Bcf/d per year must be factored in.
Unlike the Bakken, I envision that the Permian shales will rumble on for many years, since we have yet to observe any macro-scale evidence of depletion. However plateau Permian offtake rates will be determined by oil price.
Interesting insights.
Hope you continue to share your thoughts.