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 132,866 horizontal wells in 13 US states, through December 2019. Cumulative oil and gas production from these wells reached 13.7 billion bbl and 157 Tcf of natural gas. This is the first time that Oklahoma is included in these public updates. West Virginia, which just released Q4 production data, is also up-to-date.
Total production
Oil production from horizontal wells ended last year at around 8.1 million bo/d (after upcoming revisions), an increase of 0.8 million bo/d compared with the year before. Natural gas production also continued to rise last year and came in at 80 Bcf/d in December (toggle “Product” to gas), with Texas and Pennsylvania contributing more than half (select to show production by state).
Well productivity
Well productivity in the oil basins grew about 5% in 2019 (“Well quality” tab), the smallest percentage since 2013.
Supply Projection dashboard
However, with the dramatic drop in oil prices, the rig count has started a steep decline, similar as in 2015. In the past weeks we have seen many questions about how this may impact oil & gas production in the US tight basins. We therefore decide to develop a dashboard in which these kinds of questions can easily be answered. As we think that it is crucial for people affected by the current circumstances to understand how future scenarios might look like, we have made this dashboard for the time being (at least for a couple of weeks), not only available in ShaleProfile Analytics (Professional), but also publicly available on our website: US Tight Oil & Gas Projection!
The default setting will show what might happen if nothing changes (no changes in rig count and rig & well productivity), but by changing the parameters available you can simulate many scenarios, for example what would happen if no more new wells are completed:
The instructions available on this page and in the dashboard will show you the few simple steps that it took to get this.
Advanced Insights
This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected and the wells are grouped by the year in which production started.
Finally
Early next week we will have a new post on North Dakota, which just released February production data (now available in our subscription services).
Production data is subject to revisions.
Sources
For these presentations, we used data gathered from the sources listed below.
- FracFocus.org
- Arkansas Oil & Gas Commission
- Colorado Oil & Gas Conservation Commission
- Louisiana Department of Natural Resources. Similar to 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
- Oklahoma Corporation Commission – Oil & Gas Division
- Oklahoma Tax Commission
- 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.
- Utah Division of Oil, Gas, and Mining
- Automated Geographic Reference Center of Utah.
- West Virginia Department of Environmental Protection
- West Virginia Geological & Economic 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
6 Comments
[Enno: BrookPe, apologies, for some reason your comment from Thursday was not automatically approved nor visible to me for some time. We’ll investigate the cause. I’ve reposted it here]
When I started work at a major oil company in 1985, I was tasked with generating recommendations to management for approval for any investments which met their investment hurdles. This involved incorporating available technical data and tools and research of historical records associated with the assets under my position.
This work led to the well record file room, a 10,000 square foot basement room stacked from floor to ceiling with records associated with the wells drilled in our District. Reading these records, I gained increased admiration for the reservoir engineers who were then senior level managers of our company. Some were WWII and Korea Veterans, and most of their correspondence was generated when they were in an equivalent staff position to mine, in the late 50s and early 60s.
Their time was not a good one for the industry as oil prices generally ranged from $2.50- $3.50 until the 1973 oil embargo. What was fascinating to read were the discussions centered around whether a contemplated project was an “acceleration” project or a “reserve development” project. Only those projects which were determined to actually develop new reserves rather than simply accelerate existing recovery were worthy of investment. It was their job to convince management that a proposal was something not that simply met their investment hurdles, but would actually increase the ultimate recovery beyond the existing development scheme.
The reason to bring this up now is I feel the reservoir engineers in this industry have dropped the ball. We were always considered to be the adults in the room, the mature ones ensuring that the stakeholder’s capital was only deployed in those endeavors which generated a significant return ON investment. Not simply a return OF investment.
This necessitates incorporating technical data combined with the application of specific expertise into the development of a projected recovery schedule for a specific undertaking. The technical data includes well log, core, PVT, pressure transient, etc, which to my knowledge is not widely acquired or available for any of the non-conventional plays. The specific expertise is acquired in the Petroleum Engineering curriculum of any one of the fine worldwide institutions of higher learning offering such, and is more than becoming an Aries “tech” who runs “engineering” economic projection software and thinks it was brought down from Mt. Sinai, with their little league participation trophy.
One can’t know, but thinks the WWII managers would not have done this. By this meaning not applying technical data in any way shape or form to high grade or condemn drill-sites, not worrying about whether anything was simply acceleration or reserve development, and generally not employing any of the specific expertise your training provided to police the crisis it created. If all you do is chase hot production and rely on the service companies research to design the newest well completion, there is no need for you.
If the nonconventional players could have practiced some discipline based on technical justification and drilled half the wells and got 75% of the production it would have been fine. If you’d have done this, you wouldn’t have had to drill $10MM wells and triple the number of stages and run submersible pumps to create flashy ninety IPs and then slap the older more conservatively managed wells declines on that to create your fake power points. We would have had 3 MMBOPD less at half the cost and half the decline. We’d have $80 WTI and there would have been room for everyone.
All of this is a petroleum reservoir engineering failure, the greatest of all time. Belongs on the Discovery Channel’s Engineering Disasters. Am I pissed? You bet. Am I ashamed of my profession of 35 years? Definitely. That doesn’t matter. But you finally pissed off the people who could do something about it. You think the great reservoir engineers at Aramco don’t understand all of this? You think they don’t have the King’s ear? You know they do.
We come out the other side of this, get your shit together. Show some leadership and instead of producing powerpoints that project “what will never be from what never was”, start outing people who are drilling shit and screwing the investors. Inside your company and out. These plays should be mature enough for you to make that discrimination. If not, like the Virus in absence of a vaccine, we’ll find ourselves right back in the same spot. It is your job to flatten the curve. In short, re-assert your place as the adults in the room, like your 1950’s and 60’s forefathers did.
BrookPE,
Great post, thanks for the insight.
BrookePE,
Thank you so much for this very pointed and honest commentary on the state of our domestic O&G business.
I don’t suppose many people remember ENRON.
Many think Enron collapsed overnight but as I recall Enron’s collapse was much more protracted. Employees and common stockholders were locked out of trading Enron stock for months and were forced to wait out Enron’s collapse while Enron executives/insiders were free to trade and as I recall had very generous golden parachutes. My brother lost a few 100k on that deal.
Wasn’t Sarbanes-Oxley supposed to prevent another Enron?
In 2007-2009, I started watching O&G investor presentations and discovered type curves. CHK and SD presentations were particularly interesting to me. What was this magical B-factor so prominently displayed on each presentation? It never changes or it just seemed to get bigger every quarter. How could every well every time produce “gold”? It smelled bad to me. There had to be a skunk in there somewhere.
I don’t generate prospects and I don’t drill or operate. I am a landman. But I do love the engineers and geologist that tell me the truth. But I still don’t understand why so many of my professional colleagues have no sense of smell.
Enno,
Thanks for that Supply projection tool, very nicely done. I am having trouble with the secondary scenario, is that feature turned off? I was going to try a scenario with rig count increasing after Jan 1, 2023, after a drop in rig count to zero in May 2020 and remaining there until Dec 2022, but either I am doing something incorrectly (likely) or the feature is turned off/not working.
In any case, impressive work, as usual.
Dennis
Thanks Dennis,
Unfortunately, a scenario that has the rig count dropping all the way to 0 and then increasing again is not supported. The reason is that with the rig count parameter you can set the monthly percentage change. After it has dropped to 0, there is no way to get it up again (multiplication by 0).
Instead, you can try a scenario that brings the rig count very low, e.g. to 100-200 rigs, before rising again.
Also note that currently only 2 periods are supported, e.g. you can let the rig count drop and then rise again, but not with an extra intermediate period in which it stays constant. Maybe in the future.
Dennis, just a quick update: we’ve just added the possibility add a 3rd period to allow for more complex scenarios.