Visualizing Eagle Ford oil & gas production (through September)

Eagle Ford - update through September 2018

This article contains still images from the interactive dashboards available in the original blog post . To follow the instructions in this article, please use the interactive dashboards. Furthermore, they allow you to uncover other insights as well.

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This interactive presentation contains the latest oil & gas production data from all 21,698 horizontal wells in the Eagle Ford region, that started producing since 2008, through September.

Graph_01.jpg

Visit ShaleProfile blog  to explore the full interactive dashboards

Although from the above graph it appears that oil production in the Eagle Ford has moved sideways in 2018, due to the typical reporting lag in Texas, I expect to see that after revisions production from horizontal wells will come in at 1.3 – 1.4 million bo/d in September. That would be the highest level in the past 2.5 years, but still well below the 2015 peak.

 

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One reason for that is that well productivity hasn’t increased so much in the past 4 years, as you’ll see in the ‘Well quality’ tab. This despite that laterals have gotten longer (by about 1/3rd), and more frac sand is typically used nowadays (it more than doubled). You’ll be able to normalize for these factors in our online Analytics service.

 

Graph_03.jpg

The basin is aging rather rapidly, and in September almost 80% of these horizontal wells were producing below 50 bo/d, as can be seen in the bottom plot of the ‘Well status’ overview. However, that number does include about 3,000 gas wells as well (filtering these is a subscription-only feature).

 

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The 2 leading operators, EOG & ConocoPhillips, either set new production records in September, or were close (‘Top operators’).

 

The ‘Advanced Insights’ presentation is displayed below:

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In this “Ultimate Recovery” overview, the relationship between production rates and cumulative production is revealed. Wells are grouped by the year in which production started. I’ve preselected the Austin Chalk and Eagle Ford formations.

As you can see, wells from the 2010-2012 time frame are now on average below 20 bo/d, after having recovered 120-150 thousand barrels of oil (and 0.7-1 Bcf of natural gas). Wells that started in 2017 peaked at a rate of 664 bo/d, and declined to a level of 174 bo/d in the next 8 months, having recovered just over 100 thousand barrels of oil. More recent and granular data can be found if you select to group the wells by quarter or month of first production (using the ‘Show wells by’ selection).

 

The WSJ just published an interesting article in which they compared actual verses operator reported well performance. Many of our subscribers and readers have told us that they value our services due to the independent and accurate reporting of production data.

In February we will be at the NAPE summit in Houston, so please stop by our booth if you are joining this event as well.

 

Early next week we will have a post on the Permian again, on which we also have a more detailed update in our upcoming enelyst chat on Tuesday.

 

Production data is subject to revisions, especially for the last few months.

For this presentation, I used data gathered from the following sources:

  • Texas RRC. Production data is provided on lease level. Individual well production data is estimated from a range of data sources, including regular well tests, and pending data reports.
  • FracFocus.org

 

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Facebook: ShaleProfile

 

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thanks for this data - really interesting -apart from confirming the massive decline rates of oil shale, it also indicates the increase in decline rates in the Eagle ford.

 

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15 minutes ago, NWMan said:

thanks for this data - really interesting -apart from confirming the massive decline rates of oil shale, it also indicates the increase in decline rates in the Eagle ford.

 

Capture3.JPG

Shale Profile is a unique site.  Have you tried playing around with the interactive presentations on their site?

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never been on the site before - thanks will have a look

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I realised you point about the graphical relationship and you are right decline curve analysis is not usually undertaken by drawing lines on a graph, however the pink section of the graph drops 300k in one year and the green section drops 800k in one year.  I don't think anyone disagrees with the fact that less attractive area are now being drilled.  I was trying to get an idea of how this is effecting decline rates.  

Concerning "The limiting factor on flow rate is oil moving through rock".  Oil shale does not move through rock.  Shale is impermeable and all oil shale production is through induced fractures which produce a massive surface area for adjacent oil to seep into the fractures.

I agree that oil shale wells will probably produce a couple of hundred thousand barrels per day long term but the EIA don't, they have got it marked down for millions and on this resource alone America will be the world biggest producer.  So in matters that they are already drilling parts of the Eagle Ford that have even higher decline rates.

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(edited)

MtheBold,

Excellent discussion!

This 'Total production' visualization is not meant to show everything. One thing it does show well is how the total production from wells before a particular year changes over time. E.g., you can see that the total oil production from wells that started before 2015 dropped from over 1.6 million bo/d, to around 0.3 million bo/d in Sep 2018 (follow the top of the dark green area).

The total field decline % cannot be easily read from this graph. Probably this percentage has dropped, as the field contains more and more older wells that decline with a lower %. In basins were production is rising strongly, this % is typically increasing (as newer wells decline with a high rat). We do offer a data service with which you can obtain all the individual well production histories, so it would be rather easy to determine this % over time.

Regarding withholding production: although this may happen on a small scale, I have not seen it having a big impact in the oily shale plays. In the Appalachian basin, you can see this effect more, as operators produce e.g. far more gas when the winter approaches, or when new pipelines come online.

Coming back to the questions you raised about the decline in older wells. Although it may be a stable base that produces for many more years without a steep decline, older wells actually produce very little towards the total in these shale plays. In the interactive version of the above mentioned graph, it is possible to show the total production by production rate range. If you do that, you'll see the image shown below. It shows that in the EF just ~300 thousand bo/d is produced from wells that produce below 50 bo/d, which represents around 70% of the wells (and are of course mostly the older wells).

With the 'Ultimate recovery' visualization, you can easily find out how the decline behavior changes over time, also for older wells. What it typically shows is that the hyperbolic decline continues until late in life, when wells start to approach their economic limit, after which the decline steepens as more wells are shut-in.

 

 

 

EF Total production by rate.png

Edited by shaleprofile
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