Macro U.S. Oil Data (2002/2012) + Energy Independence Musings

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I felt it was time to get some macro data on this site which provides perspective for some of the “hot-button” words heard in the news media like “energy independence.” The data below compares oil and petroleum product imports during 2002 and a decade later during 2012. The U.S. imported 3.9 billion barrels of oil* (BBO) (10.6 MMBOPD) during 2012 or 8% less than the 4.2 BBO (11.5 MMBOPD) it imported in 2002.

We also used less oil in 2012 as consumption dropped 6% to 6.8 BBO (18.5 MMBOPD) compared to 7.2 BBO (19.8 MMBOPD) in 2002. Imports as a percent of total consumption have dropped from 58% in 2002 to 57% in 2012, meaning we’re not importing significantly less petroleum contrary to what many would hope as domestic production increases.
*When I refer to oil in the above paragraph, the figure includes petroleum products (see below for definition).

Let’s answer the next natural question here, how much did domestic oil production really increased during the decade in consideration? In this section we’re going to look at just crude oil which would be distinct from petroleum products.

U.S. Crude Oil Production (2002 to 2012)

Source: EIA.

Domestic crude oil production increased 14% to 2.4 BBO (6.5 MMBOPD) in 2012 from 2.1 BBO (5.7 MMBOPD) in 2002. This of course doesn’t tell the full story as crude production was tanking circa 2008 before shale production ramped up and changed the course of our energy history. I’d have to imagine there would be a lot more support for the Keystone XL pipeline if U.S. oil shale hadn’t been exploited.

If you’re wondering about exports, we shipped approximately 22 MMBO (60 MBOPD) across borders during 2012, 564% more than 3.3 MMBO (9 MBOPD) in 2002 and 49% less than 43 MMBO (118 MBOPD) in 1999. While exports increased quite a bit over the time studied, 22 MMBO is a spit in the proverbial bucket.

All in all, it doesn’t seem like we’re a whole lot closer to energy independence than we we’re during 2002 as even domestic production hasn’t increased that drastically when you look at the period as a whole. With that said, when most people think about energy independence, they’re probably throwing Canada into the mix which makes the concept slightly more feasible while also putting our energy fate in the hands of heavy crude, a dirty proposition.

U.S. Imports of Oil and Petroleum Products by Country (2002 and 2012)

Source: EIA
*Click here for definition of petroleum products.

The graph above shows we’re importing a lot more oil from Canada and significantly less from states like Saudi Arabia, Mexico and Venezuela. The decreases in Saudi Arabia/Venezuela are probably political decisions to wean ourselves off of Middle East oil/regimes we don’t want to support financially. Mexican oil production has decreased due to depletion of fields and or lack of exploration by its oil companies. The one surprise on here might be the increase in purchases from Russia and Columbia, two countries who’ve picked up some of the slack from our declines elsewhere.

EOG’s Horizontal Wells in the Greater Green River Basin

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I’ve had a bit of a posting hiatus but I plan to continue to keep this blog updated, I’ve just been busy. This post will focus on production results from 27 horizontal wells drilled by EOG Resources (EOG) in the Greater Green River Basin (see map below) in Southwestern Wyoming. These wells were drilled between 2006 and 2010 and produce from the Frontier interval which is a natural gas zone. For reference, the Frontier interval is a similar but older age rock than the Lance interval which is the productive zone at the Pinedale and Jonah fields in the Greater Green River Basin.

Map of the Greater Green River Basin

Source: USGS.

The average 30-day production rate from these wells is 1,430 thousand cubic feet of natural gas per day (Mcfpd) which corresponds to an average recovery of 369 million cubic feet of natural gas (MMcf) after one-year of production and 813 MMcf after three-years of production. Regarding the 27-wells, range of recoveries is wide with a maximum three-year recovery of 2.0 billion cubic feet of natural gas (Bcf) and a minimum of 145 MMcf.

So how economic were these wells? I haven’t been able to find any information regarding cost, but what I can do is take a look at natural gas prices from 2006 forward to ballpark what these wells have grossed to date.

Annual Natural Gas Wellhead Prices (2006-2012)

Source: EIA.

If we use $5.45 per Mcf (average price from 2006 to 2011) as the average price received per Mcf of natural gas and 813 MMcf as the average three-year recovery, we can see that these wells grossed an average of $4.4 million during their first three years of production. Without knowing well cost, we’re kind of left hanging here, but I do have a log (shown below) from an EOG well drilled in the Green River Bend field which shows depths in the 7,000′ to 8,000′ range. Based on this, I’d assume they were each drilled and completed for approximately $5 to $6 million.

Green River Bend Well Log

Source: USGS.

So what’s the payback period looking like? Assuming an 85% NRI and $5.5 million well cost, I’d guess these wells would need to produce approximately 1.2 Bcf per well with approximately 3 thousand barrels of oil to break-even. These wells only declined 30% from year one to year three, so they project to have a long production life. Knowing the above, I’d guess the payback period for 2006 to 2009 generation GRB Frontier wells is five to six years or triple the length of the average Bakken well drilled today.

With that said, the purpose of this write-up is to provide data on a pure natural gas play, something I haven’t done much of on this blog to date. Even though oil is currently more economic than natural gas, natural gas is going to play a larger role in fueling the world moving forward so it makes sense to familiarize ourselves with the potential of some of these formations.

Last, I thought I’d toss in a couple scatter plots on the wells used in this analysis. As shown below, it’s pretty easy to tell how economic a natural gas well in this field will be based on the 30-day production rate.

Green River Basin Production (Frontier Zone) Year 1

Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

Green River Basin Production (Frontier Zone) Year 3

Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

The Bakken’s Stacked Pay Zones

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Continental Resources (CLR) came out with data last winter indicating that at least some of its acreage in the Bakken would be prospective for stacked pay zones. The evidence it provided was results from its Charlotte Unit wells in McKenzie County where the company was producing from three zones, the Middle Bakken, Three Forks 2 and Three Forks 3 (see stratigraphic column below).

Source: Continental Resources Corporate Presentation

As you can see from the picture above, the company’s success in the Three Forks increased its oil in place estimates for the Bakken Petroleum System to 903 billion barrels of oil (BBO) from 507 BBO and recoverable reserves to 32 BBO at a 3.5% recovery factor. CLR has a lot of work to do to prove this assertion and it will be delineating its acreage for multiple Three Forks zone potential.

Producing from the Three Forks is nothing new in the Bakken, but what’s interesting is that CLR is producing from multiple Three Forks (TF) benches which may prove the potential of multiple reservoirs in the Bakken thus more reserves than what has been produced in the Middle Bakken.

I don’t have CLR’s well data organized well enough to show you the results of its TF wells. Part of the problem is having to dig through well files which are large documents that take a long time to open on North Dakota’s Oil and Gas Division website. Luckily, some companies give us clues that a well is a Three Forks well by putting “TFH” or Three Forks Horizontal in the well title.

Marathon Oil (MRO) is one of these companies and I have data from 26 of its wells across Mountrail and Dunn Counties, half of which targeted the Bakken and the other half Three Forks. These wells were drilled very close to each other in pairs indicating that the company believes each section is economic for both the Bakken and Three Forks.

Note: When I say the wells were drilled very close, I’m saying same quarter section at minimum with parallel lateral legs.

Cumulative production from Stacked Pay Zones

Source: North Dakota Oil and Gas Division / The Energy Harbinger.

I’ve color coded all of the above Bakken wells in green and TF wells in red. The first two wells, Rhoda 24-31H and Oren USA 31-6 TFH, are a pair of wells which were both drilled very close to each other but in different zones. What needs to be determined to prove that the Bakken and the Three Forks are separate reservoirs is that the cumulative production will not be effected by the drilling of either well, that is that one well is not draining oil from the other thus resulting in you drilling two wells for the price one.

All of these wells were drilled during 2011 and 2012 and the quick and dirty average cumulative production from them is 97 thousand barrels of oil (MBO) and I usually use 150 MBO as a target for payback from a Bakken well. This would indicate that these wells are paying back in two to four years which is a solid result and compares well with the company’s historical production in the Bakken.

There’s a lot more to talk about and analyze with regards to this topic and the implications could be large. For instance, if I have 100 Bakken well locations in my inventory but find out the Three Forks zone is productive in all of those same areas, I now have 200 well locations. All of the above wells were drilled in clusters across both Dunn and Mountrail County, meaning Marathon either doesn’t think most of its acreage is prospective for multiple zones, it’s capital has been tied up in the Eagle Ford where returns are better or it’s not following the same naming system with all of its TF wells.

I will be looking into the above for MRO as well as where other companies are drilling TFH wells in the Bakken. When I have more data on CLR, MRO, etc I’ll be writing another article.

The Well Map Update (3-20-13): Feedback

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When I initially started working on The Well Map, I was planning on building a dynamic filter into the free version you see today, before moving it to a new web platform where access would be restricted to paying customers. Don’t plan on the former being available, however there will be a free demo map with limited well map data points once the new site launches.

The new site is currently under development with an expected launch date of June, 2013. The map will have multiple filter options for county, operator and well name in addition to ranges for spud date, oil/gas production rates (30-day and cumulative), and oil cut. There will be other features built into the map too which are designed to make your experience a good one.

Are there any functions I’m missing that any of you think would be useful?

I’m also working on building in analytics to support the map data, one piece of which will be average NGL cuts where applicable as public data doesn’t break these out at this point. Are there any other analytical pieces that you think would be helpful?

I appreciate your feedback as me and my team work to complete the first build of this website.

Excerpts from Earnings Transcripts (DVN, NBL, SD, CRZO, MRO, AREX)

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I regularly spend time digging through earnings transcripts as I research the various companies and formations I write about. While it’s currently post earnings season, I thought I’d post a few notes from earnings calls from several companies I’ve recently looked at. These notes aren’t necessarily the most important points from the call, just ones that interested me.

Devon Energy (DVN)
* D&C six wells in the Cline Shale with “highly variable results.” Plans to drill 30 more exploration wells in the formation testing various intervals.
* Regarding variability of the Cline results, the company mentioned it’s testing different areas of acreage position and different intervals to see which work best. It’s confident the play will be economic.