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 113,568 horizontal wells in 12 US states, through May 2019. Cumulative oil and gas production from these wells reached 11.5 billion bbl and 131.7 Tcf of natural gas. West Virginia is deselected in most dashboards, as it has a greater reporting lag. Oklahoma is for now only available in our subscription services.
Oil production from horizontal wells in these states grew to close to 7 million bo/d in May (after upcoming revisions). As is visible in the graph above, the growth rate has significantly fallen since the end of last year.
The same is the case for natural gas production. If you toggle the “Product” selection to “Gas”, you’ll notice that production has hovered just below 63 Bcf/d since the start of the year in the selected states.
In the “Well quality” tab, the production profiles of all the horizontal wells in the major tight oil basins are selected. Well productivity (not normalized for the increases in lateral length or proppants) has still improved in the past 2 years, but by a far smaller amount than in the 10 previous years.
Based on preliminary data, at least EOG and Marathon set new production records in May (see “Top operators”). If you click on these operators in the legend, the map will show you exactly where they have produced their oil.
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.
The 11,304 horizontal wells with first production in 2014 have recovered on average 150 thousand barrels of oil after 4.5 years on production. They are now at an average rate of 32 bo/d. The wells that began 3 years later have recovered the same amount, but they are still flowing at a rate of 100 bo/d higher, on average.
Next week Thursday (September 19th) we will host our first webinar (30 mins). Based on popular request, the topic will be terminal decline rates in the major tight oil & gas basins. You can register, and already ask your questions about this topic here: ShaleProfile webinar registration page.
Early next week we will have a new post on North Dakota, which will release July production data in the coming days.
Production data is subject to revisions. For these presentations, I 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
- 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
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10 Comments
On the Nature and Character of the Widespread Oil Production Shortfalls Reported by the Wall Street Journal, by Scott Lapierre, PE:
https://www.linkedin.com/pulse/nature-character-widespread-oil-production-shortfalls-scott-lapierre/?trackingId=sEyIdyUMR7mqgGM7Vxg1%2Fg%3D%3D
Congratulations, Enno. There are a number of critical ways to use your data, particularly that found on Shale Profile Analytics, none more important than getting to the truth about exaggerated EUR’s and the ensuing “mistakes” being made with regard to America’s current energy policies, oil exports and the lack of conservation measures designed for America’s long term future.
Thank you,
Mike Shellman
Mike/Enno-
Where are these 600MBO + “average” Eagleford wells from his report
Mike, on that note. I just looked at EOG. As at Dec 2018, they had USD 28 billion in Net property, plant and equipment, i.e. developed oil assets. Their depreciation charge for 2018 is close to USD 4 billion. Using straight line it would take 7 years to write off the assets. With a corporate decline of 40%, I just do not understand how EOG can apply such a low depreciation charge. I know that the decline rates goes down with time, but still.
The asset side of the balance sheet seems grossly overstated, which is probably a result of too high EURs. I guess my real question would be, at what time will this discrepancy by so large that the accounting department no longer can hide this?
Alex-
You have found the Achilles Heel… PDP reserves at ratios of 7-8 :1 of production are BS.
In the interest of complete accuracy I see the decline as greater than 50%.
Alex, as Jim points out exaggerated PDP EUR’s, would, if re-appraised, would put a lot of these guys underwater. Add PUD crap to that, based on proximity to parent wells and lofty, lengthy type curves…its not pretty for lenders. Short of changes in SEC rules I don’t know when this will hit the fan. I would not loan, renew or re-finance any debt with any shale oil company anymore without third party re-appraisals of known assets, including up-spaced PUD locations, so maybe when maturities hit? What do you think?
January 2, 2019 – WSJ Article Published about shale overstatement
February 8,2019 Lawsuit Investigation into PXD overstatement announced
February 20,2019- Tim Dove resigns effective immediately.
February 21, 2019- Date of Stockholders of record in 10-k
February 26,2019- Scott Sheffield signs 10k
Jim,
I see fast declines more a problem than Bubble Point Death.
I believe Scott did not use/show average but only the BPD wells in the EF plots, therefore reinforcing the BPD impression, and confuse you with 600K BO+ wells dominating in EF.
I found that shaleprofile.com data do have strong evidence to support BPD is epidemic for US tight oil wells after 2008, but instead initial 5 years’ fast decline have more impact to the EUR or PDP or IRR of each well.
https://www.linkedin.com/pulse/state-tight-oil-production-decline-i-sheng-wu/?published=t
Indeed, this does not impact IRRs much, but it will impact balance sheet and thus profitability.
I suspect that higher decline rates for historical wells have been hidden by revaluation of acreage from downspacing. i.e., the undeveloped land has a higher and higher valuation despite being drilled to Swiss Cheese condition. Indeed, the acreage value should go down as a higher percentage will be Tier 2 and more wells will be child wells.
IF this is the case, big IF, such a ponzi will only work for a limited period of time. Maybe the most important line-item when Q4 2019 comes out will be “impairments”. Which is a one-off of course, so will not affect cash flow…At least this will be the claim.
A thought on how to normalize wells. Consider a 100 acre well with a 7500 foot lateral, spacing would be about 586 feet. Spacing can change and lateral length can change. Generally the number of acres for prospective drilling does not change.
Rather than normalize by feet of lateral, normalize by acres per well, if we have the spacing data.
Exactly Alex. Look at Whiting for example. If you look at the ultimate recovery graph, their average well looks to be comfortably over 60% depleted based on where they would strike 5-10 bpd on the x axis. Yet on the balance sheet their PPE is only 41% depreciated. This suggests their quarterly depletion charges are very much on the low side
There are probably some physics/engineering-type arguments that wells COULD produce more than the graphs suggest. Their assumptions are obviously being approved by engineering firms. But consultants’ stamp of approval is not necessarily a whole lot different than the ratings agencies handing out AAA ratings on bad CDOs a decade ago – “don’t bite the hand that feeds you”.