Enno Peters
This is an older blog post, you will find one on more recent data here
These interactive presentations contain the latest oil & gas production data from all 22,877 horizontal wells in the Permian (Texas & New Mexico) that started producing from 2008/2009 onward, through June 2019.
June production came in at just over 3.3 million bo/d, which after upcoming revisions will get close to 3.5 million bo/d. That would represent a growth of about 200 thousand bo/d in the first 6 months, which is significant, but well under the growth rate in the past 2 years. Since the beginning of the year, the horizontal rig count has dropped by 14% (from 443 to 383), which is now starting to make an impact. Gas production, most of it associated with oil production, was nearly 12 Bcf/d in June.
After major strides in performance in the years 2013-2016, well productivity is up only slightly in the past 3 years, as you can find in the “Well quality” tab.
Normalized for the increase in lateral lengths, well results have not increased since 2016, as you can see in the following image, which was taken from our advanced analytics service:
Pioneer Natural Resources produced almost as much as Concho, the number 1 in the basin (“Top operators” dashboard).
The ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the year in which production started.
After 2.5 years, the 2,271 horizontal wells that began production in 2016 recovered on average 206 thousand barrels of oil, in addition to 0.6 Bcf of natural gas. Their average production rate fell in this period from almost 600 bo/d to just below 100 bo/d.
Last week we held a webinar (our first!) on Terminal Decline Rates. We analyzed these rates for the major tight oil and gas basins, using a new dashboard in our analytics service. Here you can find the average annual production rate and decline rates, for all the horizontal oil wells that started in the Permian since about 2010.
As you can see in the tooltip, the average annual decline rate from year 1 to year 2 is 56%. After year 7, this annual decline rate has fallen to 10%. This dashboard also allows you of course to analyze this data for specific counties, operators, or by well vintage.
Early next week we will have a post on the Eagle Ford.
Production data is subject to revisions.
Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations.
For these presentations, I used data gathered from the following sources:
- Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests, and oil proration data.
- OCD in New Mexico. Individual well production data is provided.
- FracFocus.org
====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.
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11 Comments
From 300 BOPD to 18 BOPD in seven years…and still declining at the rate of 10% annually. From the best shale oil basin we’ve got left.
THAT’s what America’s hydrocarbon future looks like?!!
https://www.chron.com/business/energy/article/Permian-Child-Wells-May-Cut-Oil-Recovery-Up-14454806.php
Setting up the reserve report reconciliations (can’t have an 8 to 1 PDP to RP ratio in the Permian) and the write-downs coming. How may prime locations have these companies claimed in the past? I think at least 15-20 years.
“We told you so” is better than no explanation at all. Wise move.
Inside all the Consulting engineering companies this Fall
Dec 2016: Decline through June next year: 35%
Dec 2017: Decline through June next year: 40%
Dec 2018: Decline through June next year: 44%
Why is the initial decline accelerating? Parent/child?
Alex-
That’s a good catch. The foundation is eroding.
Result of too big a wellbore/fracture/area for the rock you’re in.
Below is an overdesigned well for what it drains.
Further evidence of foundation erosion…
On terminal decline for Permian, I wonder if the 10% rate might be using too small a sample?
If we consider 2009 to 2011 wells and take the weighted average of wells up to 91 months we have a sample of 1066 wells. I took the natural log of monthly output and fit a trend line to the straight line portion of the data. I don’t have any way to remove refracked wells from the data so this may explain the difference in my result from Mr. Peters’ which suggests a 10% terminal decline rate. I get about a 14% terminal decline rate, perhaps due to refracked wells. At 91 months the average well in this set of 1066 wells which started producing between 2009 and 2011 was producing about 14 bo/d.
In any case another data point to consider, I use a 15% terminal decline rate for Permian wells in my models based on earlier data (from about a year ago) presented by Mr. Peters.
You might be calculating it differently. I think your technique is the exponential decline Dexp=-ln(q2/q1). Enno’s decline is 1-q2/q1.
I prefer the exponential decline since Np=365(q1-q2)/Dexp, it is a quick way to relate rate and reserves.
brookpe,
I did not catch that difference, it is possible the production data might change to a different slope after 7.5 years. So far the data is rather limited (only a few hundred wells) beyond 7.5 years, but that trend looks fairly linear over 4.5 to 7.5 years. I am not a petroleum engineer and don’t have enough experience to judge if the slope might change after a 3 year straight line trend. Perhaps oil pros could offer their perspective. Does the pe, suggest petroleum engineer, or perhaps professional engineer?
Thanks.
It suggests both.
To be honest, it seems quite difficult for people to grasp such a simple concept as q2=q1E^-dt, I thought it was high school biology stuff. When you say a 14% decline, I think 7 year reserve to production life, its just that simple.
This is the heart of the problem, these companies are booking the PDP reserves like their conventional reservoirs with an 8 to 1 Reserve to production ratio (12.5% decline), but the PDP curve of the base is declining over 70% in year 1, you can’t make the average 12.5% happen by making up for it in year 7 at 14% at one tenth the rate! The PDP ratio should be 4 at the most, and that is a stretch. If the PDP reserves were trued, the stock values of these companies would crater. Depends on whether you can handle the truth or not.
PDPR/P is a metric that always gets skated over; thanks, Jim. If these shale oil PDP reserves were trued, 80% of them would be underwater with their lenders and basically insolvent. That is a cat that not very many want out of the bag.
Steve StAngelo points to steepening decline, something we’ve discussed for years. He is using Enno’s data.
There is still room for growth left but it definitely slowing and if D&C stops – it won’t take long to remove all spare production capacity and than some. Question is – what would be new demand level at a time.