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 119,057 horizontal wells in 12 US states, through October 2019. Cumulative oil and gas production from these wells reached 12.6 billion bbl and 142 Tcf of natural gas. Ohio and West Virginia are deselected in most dashboards, as their production data is less current. Oklahoma is for now only available in our subscription services.
Since the start of 2019, oil production in the 10 selected states grew steadily to 7.4 million bo/d in October. After revisions another 100 kbo/d or so should be added. Note that due to the omission of Ohio, these numbers are not comparable to the last update. This marks a growth rate of ~0.9 million bo/d y-o-y, still significant, but only a little more than half the rate seen a year earlier (1.6 million bo/d).
Completion numbers are slightly down through October compared with the year before (9,344 vs 10,073).
The next tab (“Well quality”) visualizes how well performance has changed over time in the major tight oil basins. There were significant improvements every year from 2013 to 2016 as completion designs advanced. In the last 3 years the rate of productivity improvements has markedly slowed, probably due to a mix of better completions but tighter well spacing.
It took the 7,000 wells that commenced production in 2012 7 years to recover 150 thousand barrels of oil, on average (see the bottom chart). Newer wells recover that amount in less than 18 months.
Most of the leading shale operators slowed production growth in 2019 (see “Top operators”). Exxon Mobil was a clear exception, as it doubled output in just 1.5 years.
The ‘Advanced Insights’ presentation is displayed below:
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.
You can find here that the wells which began production between 2010 and 2012 are nowadays near a production rate of 20 bo/d and that they have recovered so far just over 150 thousand barrels of oil, on average. Newer wells are on a trajectory to do about double that amount (they also peaked at over double the rate).
The following graph, taken from ShaleProfile Analytics, shows how lateral lengths and proppants have changed in the previous 6 years:
Laterals grew by almost 50%, while proppant loadings more than tripled, on average. Of course there are major differences between basins and operators, which all can be analyzed in our service.
We were happy to find that the JPT wrote an interesting article about the behavior of shale wells after more than 5 years on production, supported by our analytics service: Life After 5: How Tight-Oil Wells Grow Old
We are in Houston this week to visit friends and customers, and to show our latest work at the Nape summit on Thursday and Friday. Using a mix of traditional decline methods, machine learning and statistics, we are now able to create 20-year forecasts for most of the horizontal wells in the US. Visit our booth (#3019) to see how that looks for the areas where you are interested in.
Early next week we will have a new post on North Dakota.
Production data is subject to revisions. For these presentations, we used data gathered from the sources listed below.
- 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
- 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
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.
The JPT article referenced above is a shot across the bow of every reserve auditing firm out there as 10k signing time approaches- It is impossible to have an 8 to 1 PDP reserve to production ratio as several companies do… that is 30 year life stuff.
“At 5 years of age, horizontal wells in the Permian Basin and Williston Basin’s Bakken Shale share average terminal decline rates of around 17%. The figure for wells of the same age in the Eagle Ford Shale is 23.5%. On average, it takes 8–10 years for many of these wells to fall below an annual decline threshold of 10%.
These terminal decline rates represent a clear challenge for current reserves and ultimate recovery estimates from wells that were expected to produce economically for 30 or more years.
As a result, shale producers are now advised to not use conventional wells as a guide, or else run the risk of overstating and overvaluing unconventional assets (URTeC 432). The sector’s awareness of long-term production shortfalls is also considered to be the driving force behind a new wave of mergers and acquisitions that has left constrained operators seeking to combine with peers holding proportionally large positions of undrilled acreage.”
I am surprised to find that the wells with first production in 2010, which number over 6,000, are producing on average a little more than 5 BOPD. After royalties, that is 4 BOPD. At $50 oil, that is gross revenue of just $73,000 annually. There is no way these wells are economic. One downhole failure has to guarantee an annual loss for a well with a TVD of 8,000’ or more.
I have not looked for awhile, but in 2015-2016 I studied many lease operating statements and joint interest billing statements for shale wells in the three major shale oil basins. For mature wells, LOE ranged from $3,000 to $20,000 per month. I don’t recall seeing anything under $3,000 per month.
The state regulatory agencies should be making plans now for the plugging and abandonment of these wells, which number over 120,000 per shaleprofile, and which are expected to number 300,000-400,000 total.
I suspect these wells will not be fairly simple to plug compared to shallow vertical oil wells.
Just a quick comment: in 2010 quite a number of gas wells began production (Barnett, Haynesville & Fayetteville). If you remove those (possible in our services), you will find that the oil wells from that year are on average still just above 20 bo/d.
Enno. My mistake, one that maybe I have made before. 20 BOPD shale wells can show a net positive result annually if there are none, or maybe one, down hole failures per year.
However, at 20 gross BOPD, the profit at $50 WTI after all expenses is maybe going to be in the $100,000 range, with a lot depending not only on down hole failures, but also water disposal costs. So at this point, the well is returning between 1-2% of the initial investment in my estimation.
I found what might me a good example of LOE in the Eagle Ford. Non-operated WI for sale in 96 wells of various ages. The average BOPD per well if 40 gross barrels, the average MCFPD is 55 gross. NRI ranges from 75-78%.
The average LOE per month per well over the past six months comes is $14,300 per month. So in the ballpark of $15-16 per well if gas is not included.
As always, anecdotal, but is evidence that when these wells get down below 25 gross BOPD, net income is minimal in relation to the initial investment.
Thanks for sharing this Shallow S. I am very interested in getting more information about costs in all the tight plays.
The tight oil wells which started producing in 2010, had about 3 years of output with oil prices at $90/bo+. Is it possible to wait on the downhole repair on a well (temporarily abandon) until oil prices rise?
It would seem to be a wise business decision, but there are no doubt many factors that I am missing as I am not an oil producer.
Privy to lots of shale oil JIB stuff lately I am surprised how much OPEX is actually capitalized and how high liquids OPEX is when not diluted by BOE. At $48 WH prices it’s pretty clear to me real economic limits are 8-12 BOPD depending on basin and WOR. At $40 in the Bakken EL must be +15 even without high WOR.
20 BOPD is still declining annually at an alarming rate and that well is facing large P&A&D liability; once the well gets to the 20-30 BOPD level I think its PDP market value in an asset sale is nil. “Consolidation” between companies based on PDP alone, when debt is assumed, is probably NOT going to happen; if consolidation is based on PUD reserves, facing continuous drilling commitments or loan covenants, who has the capital, now, to realize that value?
Sadly, and completely avoidable it all was, the shale thing is unraveling quickly now. Both sectors are continuing to drill themselves into oblivion.