This is a brief update on Eagle Ford Crude plus Condensate (C+C) output through February 2014. It can also be found at Peak Oil Climate and Sustainability.
Figure 1- RRC Data provided by Kevin Carter
I have used my usual method of estimation where I find the percentage of total Texas(TX) C+C output that is from the Eagle Ford(EF) play (I call this %EF/TX ) and multiply this by the EIA’s estimate of TX C+C output.
The chart shows the Railroad Commission of Texas (RRC) Eagle Ford estimate (EF RRC) in thousands of barrels per day (kb/d), the EF est (kb/d) as described above, the percentage of EF C+C that is condensate (EF %cond/C+C), and the %EF/TX also described above.
As before I would like to thank Kevin Carter who created a method to simplify gathering the Eagle Ford data.
I have done estimates of Eagle Ford output several times before (April 2014 and August 2013) and I would like to take a look back at those previous estimates to see how they compare with my most recent estimate.
Keep in mind that the initial RRC estimates (most recent 12 months) are not very accurate and for that reason the %EF/TX estimate for the Mar 2013 to Feb 2014 period is just a rough estimate with the most recent months with the greatest error.
My assumption is that if the overall TX estimate is 20% too low, that the EF estimate will also be low by about 20%, if that is correct then the %EF/TX estimate may be close to correct.
One possible problem is that because the percentage of TX C+C output from the EF play has been growing, the lag in accurate data may cause the %EF/TX estimate to be too low.
On the other hand when EF output growth begins to slow down, the EIA estimates of TX C+C will tend to be too high because the EIA has assumed for the past 12 months that TX output has been increasing by about 48 kb each month.
These two effects may have balanced each other over the past 9 months or so, but it looks like Eagle Ford growth in output may be slowing down, if so the present estimate may be too high.
Note that in the chart below the upper set of lines are the %EF/TX and are read off the right vertical axis (22% in Jan 2012 and 42% in Feb 2014).
Figure 2- Chart by Dennis Coyne (with help from Kevin Carter)
Over the period from August 2013 to May 2014 my method for estimating Eagle Ford output has tended to give an estimate that was slightly on the low side, so the method may be conservative.
Note that the estimates from August 2013 and January 2014 did not use the full Eagle Ford data set, but the Fields assessed account for about 99% of Eagle Ford C+C output in those earlier estimates. The April 2014 and May 2014 estimates include all Eagle Ford output reported by the RRC.
Texas Condensate and Natural Gas
Jeffrey Brown has done an estimate of worldwide condensate output based in part on Texas C+C data so I decided to investigate how Texas condensate output has changed over time (June 1993 to Feb 2014).
In order to see how condensate output has changed we need to consider the output of natural gas in Texas as the condensate is a byproduct of natural gas production.
There are two types of natural gas reported by the RRC of TX, natural gas from gas wells (called GW gas by the RRC) and associated gas from oil wells (called “casinghead” gas by the RRC).
I combine these two types of natural gas and call it “all gas” and then look at how the percentage of casinghead gas to all gas (%casing/all) has changed over time. It has varied from 24% in 1993 to 8% in 2008 and rose back to 22% in 2014.
I also report all TX natural gas output (all gas) in billions of cubic feet per day (BCF/d). In addition I look at the barrels of condensate produced per million cubic feet of GW gas produced [cond/GWgas(b/MMcf)] plotted on the left vertical axis which has increased from 7 b/MMcf in 2009 to about 20 b/MMcf in 2014.
Lastly I considered the %cond/C+C for all of TX (I had looked at this only for the Eagle Ford above), this has increased steadily from 7% in 1995 to 15% in 2013 (this started well before the Eagle Ford took off in 2010) and has now fallen back to 13% in 2014.
Figure 3
Aside from Texas and OPEC we have little data worldwide on condensate output.
Output of C+C from OPEC and Texas accounted for about 45% of world C+C output in 2013 (EIA data), if the rest of the World has condensate output in similar proportions to OPEC and TX, then it is possible that the increase in world C+C output since 2005 has been all condensate and that crude output has not increased.
The problem is that we lack the data to verify this, so in my view the focus should remain on crude plus condensate output.
Eagle Ford Model
Figure 4
I have also decided to update my Eagle Ford model using the EIA’s 2014 Annual Energy Outlook(AEO) Reference Oil Price Scenario. The model I presented in April used an unrealistically high real oil price scenario. The models are compared above with the two different price scenarios. A couple of other changes were made to the model:
- In the previous model the maximum number of wells added each month was 225 wells per month, in the present models the wells added gradually increases from 229 wells per month in Feb 2014 to a maximum of 270 wells per month in Jan 2017, this increases peak output by about 80 kb/d (1480 kb/d vs 1400 kb/d).
- The maximum rate of decrease in new well estimated ultimate recovery(EUR) is reached over a 30 month period rather than 18 months in the previous model and a higher maximum monthly rate of decrease in new well EUR (2% per month maximum vs 1.5% per month in the previous model) was also used. The TRR for these models is 6 Gb (when no economic assumptions are used), this is output in a World where oil companies do not care about profits.
Figures 5 and 6 below show the real oil price as a red line (read prices on right axis). The real net present value (NPV) of future oil output from the average new well, the real well cost, and real profits (NPV-cost) from an average new well are shown on the left axis in millions of 2013$. Economic assumptions are:
Annual Discount Rate 7%
Royalties and Taxes 24%
Transport Cost $3/barrel
OPEX $4/barrel
all $ are constant 2013$ (real dollars)
Figure 5
Figure 6
In figure 7 below I present the average well profile for a well starting production in Jan 2013 and Jan 2018, clearly the Jan 2018 well profile is only a guess. The January 2013 average well profile is assumed to have remained about the same from Jan 2010 to the present and to begin decreasing in August 2014.
Each month from Aug 2014 to Dec 2017 (41 months) has a separate well profile, with each successive month slightly lower than the next. So between the blue and red curves shown in figure 7 there are 41 separate well profiles and they continue below the red curve as well.
Figure 7
Note that the blue curve is based on actual well data from 317 Eagle Ford wells gathered from the RRC of TX online database.
All wells have at least 12 months of data and started production between August 2010 and August 2012 and were either in the Eagle Ford 1 or Eagle Ford 2 fields.
The average of these 317 wells is used to find the average new well profile, the data is shown in green in figure 7.
Figure 8
The chart above shows how the new well EUR changes over time, the changes in the annual rate of decrease in new well EUR (on right axis), and the number of new wells added each month.
In the middle of 2014 it is assumed that the sweet spots will be fully drilled and oil companies will begin drilling in less productive areas, it is for this reason that the new well EUR will start to decrease after remaining roughly constant from 2010 to 2014.
The maximum rate of addition of new wells and the maximum rate of annual decrease in new well EUR are reached in Jan 2017 and remain at that level until Jan 2018.
Why do these rates then fall in magnitude after that date?
The explanation is found in figure 5 above. Profits reach too low a level by early 2018 for some oil companies to think it worthwhile to continue drilling and they drill fewer wells.
As profits approach zero in mid 2019 very few companies will be drilling and the rate that new wells are added falls by a factor of 10 over a 20 month period. The slower pace of drilling causes the rate of decrease of new well EUR to also fall by about a factor of 10.
Note that figures 7 and 8 are for the AEO Reference Oil Price case shown in Figures 4 and 5 where the ERR=5 Gb and real oil prices rise to $130/barrel in 2013$ by 2032 from about $100/barrel in 2015, a 1.5% annual rate of increase in real oil prices.
Plantagenet on Sat, 17th May 2014 10:28 am
Looks like the glory days of Fracking in the Eagle Ford are rapidly coming to an end. Fracking has provided a nice boost to the US economy but unfortunately we’ve wasted the opportunity to use these funds to smoothly transition to a post-carbon economy. Now we’ll have to do it the hard way.
rockman on Sat, 17th May 2014 11:49 am
Plant – And that’s the basic problem: “…we’ve wasted the opportunity to use these funds to smoothly transition to a post-carbon economy”. As Tonto said to the Lone Ranger: What do you mean ‘we’? These ain’t your funds, the piblic’s funds, the govt’s funds, etc. They are the oil patch’s funds. And the management of the pubcos (as required by federal SEC law) are spending those funds to benefit shareholders. To stop spending capex to replace reserves and begin to move towards any other business plan would destroy equity in the short to moderate term. Granted it will go that route eventually. But higher oil prices have given an extension. And if NG prices rise soon enough that will extend the ultimate demise a bit further.
So the world is full of venture capital…much more then what the oil patch is spending. So if investing in the alts would be a good plan then it has to be much better investment for other folks. So if it is why ain’t it happening already? That would be the solution…right? The oil patch does what it can to maintain fossil fuel production while the alts are grown. So again why hasn’t the process started? Could it be that the venture capital folks don’t see a sufficient ROR to make those investments? The alts are the future. But apparently from the investor viewpoint the future ain’t here yet.
So if it isn’t a viable business plan for them how could it be for an industry with $trillions invested in infrastructure and is already struggling to maintain market cap?
bobinget on Sat, 17th May 2014 12:06 pm
Not so fast though.
First of all we don’t know the price of oil next month much less 2019. We can hope it remains stable but
inflationary pressures, geopolitical events, trump.
The entire MiddleEast is in transition, Nigeria, Africa’s richest nation a shambles. Catholic SouthAmerica’s
population, growing exponentially. Goods demands forcing Inflationary pressures.
Europe, adjusting to slower growth.
The elephant in the room will be climate change.
CC deniers are hedging, coming round to facing the task of mitigation while still insisting weird weather is strictly a natural occurrence. The GOP will either need
to listen to a few younger, influential evangelicals
or lose another important piece of their diminished base.
Funds wil be moved from Military defense to Climate defense.
Hurricane season in the middle of an El Nino could be a sad catalyst for change.
Bottom line, we are in for the mother of all public construction booms.
Needless to say, this will take lots of oil.
rockman on Sat, 17th May 2014 3:19 pm
Bob – And that’s the big problem with EIA and other projections: they are not just projecting production and consumption but have to model the entire dynamic. And that means predicting oil prices, global economic activity but focused on the bigger oil consuming nations, drilling activity which loops with not only with oil prices but capex availability and geologic limitations. And other factors, such as ELM and geopolitical changes.
They just predicted producers will have to increase by 900,000 bopd to meet demand. But as you point out demand will be determined by the price of oil as well as the health of the major oil consuming economies. But price will be also be moderated by production capabilities which will be related to oil prices but lagging behind several years.
Bottom line: they aren’t really just predicting one or two metrics but are estimating the entire geologic, drilling investment, consumption, production, oil price, political and economic viability of a number of nations. Plus probably some equally important factors I left out.
But I don’t necessarily fault their model if it really is constructed properly. That isn’t a given with any model. I wouldn’t offer judgment on their model either way. But models are not best used as predictors IMHO. They allow you to alter the assumptions in the model to determine the relative sensitivity to the various factors I just described. But a model can’t predict the future accurately unless all the key factors are correctly predicted. And then only if the quantitative relationship between all he factors is properly defined. Consider what seems like and obvious relationship: increasing oil prices reduces consumption. But current oil prices are much higher then they were just 10 years ago. And current oil consumption? Instead of decreasing it is at record levels. Don’t get that relationship correct then you model is a piece of crap IMHO. LOL.
And who has such a well tuned crystal ball to get even close to accurately predicting all those factors? As I’ve said many times: modeling is like masturbation: there’s not a damn thing wrong with either. Just as long as you don’t start believing it’s the real thing. LOL.