Updates
November 17, 2019: note comments below. From a reader:
a. I think you are being too hard on them, to dismiss all the work based on one thing.
b.
I don't think you really understand what they are doing. They are
probably trying to do some math on total average infill density, without
manually mapping each lateral. If you follow the directions in the
paper and go to Figure 8, like they tell you to, this is explained in a
very upfront manner:
"(c) Calculate wellhead density by counting the number of wells on each of the one-square-mile squares. This map is not the real well density map, because it only shows
the wellhead density.
(d) Calculate an approximate well density map from wellhead density map. The algorithm is as follows: (1) For each well, record its lateral length and calculate the number of squares, n, intercepted by the lateral. For example, a 5000 ft lateral will occupy one square and a 10,000 ft lateral will occupy two squares because one mile is 5280 ft. (2) Search for the least occupied n squares in all possible directions (i.e., north, northeast, east, southeast, south, southwest, west and northwest).
(3) Increase the value of well density by 1 well/mi2 for every least dense square found. (4) Repeat the process until all wells in the area of interest are exhausted.
(e) Calculate an infill potential map by subtracting the calculated well density from the maximum number of wells, Nmax (e.g., Nmax = 4 wells/mi2 to avoid frac hits). The summation of all values in the map is the infill potential for the one-square-mile grid.
What
they are doing is perfectly adequate. (It's actually similar to a
point that I made to you a while ago, when you were confusing wells per
unit (for larger than normal units or longer than normal well lengths,
with what matters, horizontal lateral spacing.)
November 17, 2019: from a different. Source a graphic that the Saudis [apparently] missed:
November 17, 2019: after seeing the paper at the original post, a writer suggested a paper delivered at an oil conference in Houston, TX, July, 2018, "Production Optimization Using Machine Learning In Bakken Shale." The abstract is available but there is a fee for the entire paper. The abstract, but no conclusion:
Researchers from both industry and academia have studied the tight oil resources intensively in the past decade since the successfully development of Bakken Shale and Eagle Ford Shale and made tremendous progress.
It has been recognized that locating the sweet spots in the regionally pervasive plays is of utter significance.
However, we are still struggling to determine whether the dominant control on shale well productivity is geologic or technical.
Given certain geological properties, what is the best completion strategy?
Most of the previous studies either analyze the completion data alone or divide the entire play into different data clusters by map coordinates and depth, which may neglect the heterogeneity in thickness and reservoir quality parameters.
In our study, we first conducted stratigraphic and petrophysical analyses, using the regional variation in depth, thickness, porosity, and water saturation to capture the regional heterogeneity in the Bakken Shale Petroleum System.
We selected approximately 2,000 horizontal wells targeting Mid Bakken Formation with detailed completion records and initial production dates during 2013 and 2014. Completion data inputs include normalized stage length, stage counts, normalized volume of fluid, and normalized volume of proppant.
November 17, 2019: a reader with experience in the oil fields in Saudi Arabia
as well as experience in Saudi academe of Saudi Arabia did not mince words when he saw this article. He wrote:
Like you say, bottom hole locations are always reported. They say
not. This proves they are either hopelessly careless, simply too lazy to
really do the hard research or intentionally vague. Does it matter which
one it is? No.
He wrote more but not sure if anonymity might be an issue, so I will leave it there.
Original Post
A reader sent this comment and the link to this peer-reviewed technical article:
In a way some of the most interesting [data/conclusions] I ever have read about the Bakken system.
And
this is great to see that that they have a [well-argued] forecast, but [likely quite short].
And you have a map of the core area in the middle
Bakken and Three Forks. I nearly agree about that part.
But
my initial thoughts are that they think there will only be 8 wells in a
spacing unit and no mention of the famous halo effect.
But anyway it's so
great to see what the Kingdom thinks. And they will be surprised.
I agree with the reader. I was going to go through the article and make comments as I went along, but a) the paper in many respects is too technical for me; 2) the authors are experts (and I'm not); 3) the authors have access to databases, computer programs, and statistical analysis I cannot possibly replicate.
The reader is correct: the authors assume a maximum of eight wells in each 1280-acre drilling unit. Perhaps that is accurate as an
average across the entire Bakken but my hunch is that there will be a minimum of four wells in each 1280-acre unit in non-core North Dakota Bakken, but upwards of 12 to 24 wells in the core Bakken.
Their conclusions in bold that jumped out at me,
my comments in red:
- author's conclude that newly completed wells have almost the same ultimate recovery as the older ones, despite their much higher initial oil rates
- they have the databases and the stastical data, but anecdotally, I'm certainly not seeing that
- ultimately, we predict that the 14,678 existing wells in the Bakken will produce 5 billion bbls of crude oil by 2050 (~ 340,000 bbls/well)
- currently, the Bakken is producing about 1.4 million bopd or "365 x 1.4 million bopd" = 511 million bbls per year
- after drilling an additional 4,400 new wells at the rate of 120 wells/month, the core are of the Bakken will be drilled out by 2021, and ultimate recovery will be 7 billion bbls of oil
- with 26,500 more wells drilled in the noncore area until 2041, ultimate recovery in the Bakken might be 13 billion bbls of oil, but drilling of such scale is unlikely to happen
Compare their conclusions with the conclusions of
the USGS, the 2013 assessment. Their conclusions, some of them almost laughable:
• We have provided a transparent hybrid method of forecasting oil production at shale basin scale.
• Our statistical approach generates the non-parametric well prototype templates that are used to calibrate our physics-based flow scaling with late-time radial inflow.
• In particular, our average P50 well prototypes follow the physics of linear transient flow and are used to calibrate the physics-based scaling extensions to 30 years on production.
• A combination of GEV statistics with physical scaling matches historical production data almost perfectly and gives a smooth, physics-based estimate of future production.
• Our prediction of the Bakken future is optimal in the least square sense; in other words, our prediction is as good as it gets given all data at hand.
• Regulators may want to consider our approach as a prerequisite to booking reserves in oil shales (my favorite).
• Newly completed wells have almost the same ultimate recovery as the older ones, despite their much higher initial oil rates.
• Ultimately, we predict that the 14,678 existing wells in the Bakken will produce 5 billion bbl of oil by 2050 (∼340 kbbl/well).
• After drilling additional 4,400 new wells at the rate of 120 wells/month, the core area of the Bakken will be drilled out by 2021, and ultimate recovery will be 7 billion barrels of oil.
• With 26,500 more wells drilled in the noncore area until 2041, ultimate recovery in the Bakken might be 13 billion barrels of oil, but drilling of such scale is unlikely to happen.
• Policy-makers should beware of assuming that oil boom in the Bakken shale will last decades longer.
********************
I think the biggest problem I have with this paper is the fact that "all" locations drilled prior to 2014 will eventually be re-fracked using up-to-date completion strategies . In addition, "all" Bakken wells will go through a series of small and large re-fracks over the course of their lifetimes, something not addressed in the paper. The analysis seems to be done using "conventional" methods.
Will we ever see a new USGS assessment of the Bakken?
*******************************
Miscellaneous Comments
In Progress
Page 9, line 163:
We have calculated the number of wells that can be drilled in the future in every one-square-mile pixel of the grid that covers the entire Bakken play. In order to calculate infill potentials, one should first determine well density. However, the publicly available data rarely provide information about the bottomhole locations of the wells. Instead, only surface locations are reported as latitude-longitude coordinates. Therefore, we have developed an algorithm that allows us to predict the bottomhole well density from surface well locations.
Comment: in the big scheme of things, this does not matter, but every permit specifies the exact location of the bottomhole, so I'm not quite sure what the authors mean when they say "the publicly available data rarely provide information about the bottomhole locations of the wells."
