Oil Field Models, Decline Rates and Convolution

The eventual peak and decline of light tight oil (LTO) output in the Bakken/ Three Forks play of North Dakota and Montana and the Eagle Ford play of Texas are topics of much conversation at Peak Oil Barrel and elsewhere. 

 The decline rates of individual wells are very steep, especially early in the life of the well (as much as 75% in the first year for the average Eagle Ford well), though the decline rates become lower over time and eventually stabilize at around 6 to 7% per year in the Bakken. 

 What is not obvious is that for the entire field (or play), the decline rates are not as steep as the decline rate for individual wells. I will present a couple of simple model to illustrate this concept.

Much of the presentation is a review of ideas that I have learned from Rune Likvern and Paul Pukite (aka Webhubbletelescope), though any errors in the analysis are mine. 

 A key idea underlying the analysis is that of convolution. I will attempt an explanation of the concept which many people find difficult.

I think the best way to present convolution is with pictures. Chart A below shows a relationship between oil output (in barrels per month) and months from the first oil output for the average well in an unspecified LTO play. 

 This relationship is a simple hyperbola of the form q=a/(1+kt), where a and k are constants of 13,000 and 0.25 respectively, t is time in months, and q is oil output. Chart A is often referred to as a well profile. The values for the constants were chosen to make the well profile fairly similar to an Eagle Ford average well profile. EUR30 is the estimated ultimate recovery from this average well over a 30 year well life.

Eagle Ford Output and Texas Condensate and Natural Gas

Edit: May 14, 2014

Material was added on May 14 to update my Eagle Ford Model, see end of post.

This is a brief update on Eagle Ford Crude plus Condensate (C+C) output through February 2014.  February Eagle Ford C+C output was about 1200 kb/d by my estimate.

 

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 (%EF/TX is the label that I use) 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.

Eagle Ford Update

Figure 1

It has been a while since I have updated my estimate of actual output from the Eagle Ford.

Kevin Carter (KC at Peak Oil Barrel) graciously offered help pulling together data for the 39 fields which make up the Eagle Ford play (see this page at the RRC of TX, spreadsheet download here .)
Kevin has strong programming skills in Visual Basic for Applications (VBA) and has made the job of gathering the Eagle Ford data considerably easier.  Thank you Kevin!

My previous estimates only included the Eagleville fields (Eagle Ford 1 and Eagle Ford 2 and the inactive Eagle Ford and Eagle Ford Sour fields), Briscoe Ranch, Sugarkane, Dewitt, Gates Ranch, Hawkville, and Eagle Ridge fields.  Together these 10 fields produce about 99% of Eagle Ford C+C output so these previous estimates are not bad, this new estimate includes all Eagle Ford output reported by the RRC from June 1993 to January 2014.

Note that from June 1993 to Dec 2006 C+C monthly output from the Eagle Ford play was 12 b/d or less, which is why the chart starts at Jan 2007.

An Excel spreadsheet with the data can be downloaded here .  More below the fold.

Bakken and Eagle Ford Revised Scenarios

Edit: April 2, 2014  This post was a failed attempt at humor on April Fool's Day.  When a "joke" has to be explained, clearly it is not funny.  I apologize to those who took this seriously.

Essentially I was trying to see what it would take to arrive at the 24 billion barrels of Bakken oil that Harold Hamm often claims.  It takes 69,000 wells (at 2400 new wells per year) and no decrease in new well EUR (up to 2041) to accomplish this with a realistic well profile (similar to USGS estimates).  I really thought that people would realize (given the date), that this should not be taken seriously.

I was incorrect and again my apologies.

Dennis Coyne

Figure 1

There has been a lot of discussion about the United States as the new Saudi Arabia.  Output of crude plus condensate has been expanding rapidly in the light tight oil plays in North Dakota (Bakken) and Texas (Eagle Ford).  In the past I have been very skeptical of how long this rapid increase could continue.

The argument was basically that some areas are more productive than others and that these “sweet spots” would run out of room for new wells eventually and that well productivity would decrease.

I have revised my thinking based on the continually upbeat predictions by CEO’s of successful oil companies such as Harold Hamm of Continental Resources.  In addition, there have been several encouraging pilot projects suggesting that well spacing might be dramatically reduced.  This will allow many more wells to be drilled than the 40,000 wells that I have often used in previous scenarios.

North Dakota Bakken Scenarios

Fig 1 TRR 6 to 11.3 Gb

A recent post at Peak Oil Barrel by Jean Laherrere suggested an ultimate recoverable resource(URR) for the North Dakota Bakken/Three Forks of about 2.5 Gb based on Hubbert Linearization.  This conflicts with a recent (April 2013) USGS mean (F50) estimate of 8.4 Gb.  I decided to update my scenarios based on the range of USGS estimates from F95=6 Gb to F5=11.3 Gb for the North Dakota(ND) Bakken/ Three Forks.  Note that at year end 2011 there were 2.6 Gb of crude proven reserves in ND and at the end of 2007 about 0.5 Gb, I will assume all of this reserve increase came from the Bakken/ Three Forks, so 2.1 Gb of proven reserves added to 0.35 Gb of oil produced from the Bakken/ Three Forks gives us 2.45 Gb for a minimum URR.  The Hubbert Linearization points to about 0.05 Gb of undiscovered oil whereas the USGS suggests 3.5 to 8.9 Gb of undiscovered technically recoverable resource(TRR) in the North Dakota Bakken/Three Forks.

Note that Mr. Laherrere has forgotten more about geology than I know. He may have information that I don't have access to or has read the USGS April 2013 Bakken/Three Forks assessment and found that the report was not credible.  I have assumed in my analysis that the USGS analysis is correct, if it is not then my analysis will also be flawed.  I would love to hear from Mr. Laherrere about the specific problems he sees with the USGS analysis, I no doubt would learn much.