This was also posted at Peak Oil Climate and Sustainability
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.
The EIA just published their latest Drilling Productivity Report. They kept their very linear increase for all LTO plays except for the Bakken. Strangely they updated their Bakken data right up through January according to the data they apparently received from North Dakota.
The last data point is February for the North Dakota data and May for the DPR data.
But the EIA posted some strange Legacy Decline numbers for the Bakken;
Now this just doesn’t make any sense. The legacy decline is supposed to be the number of barrels per day all the wells in the combined declined. That number should increase, but gradually as new production comes on line. That is the more production the greater the decline. They have the decline rate at 60,553 bp/d in November, jumping to 123,248 in December, then falling back to 63,459 in January. That is impossible! The decline, in barrels per day, increases as production increases. But if production decreases then the number of barrels per day that declines must decrease, not increase.
The latest Update on Bakken and North Dakota LTO production is out.
ND Monthly Bakken Oil Production Statistics (Bakken Only)
ND Monthly Oil Production Statistics (All North Dakota)
Bakken production in February was 888,398 barrels per day and all North Dakota February production was 951,350 barrels per day. Some revisions were made in the past production numbers. Only the last three months were significant however. Listed below are the actual production changes, per month, for the last three months:
Month Bakken North Dakota
Dec 13 -45,528 -40,284
Jan 14 6,542 -2,218
Feb 14 16,643 16,224
The Director’s Cut for this has not been published yet. I will update this post when it has been. There were 119 additional wells in the Bakken and 79 in all North Dakota. That means a lot of North Dakota Wells were shut down.
A Bismark engineering firm has calculated the probable Bakken Peak.
Competition from Texas, winter expected to limit ND oil production
MINOT, N.D. – North Dakota oil production, which is poised to break the 1 million barrels per day benchmark, will peak at 1.2 million to 1.5 million barrels per day over the next five years, limited by winter weather and competition from Texas, a Bismarck engineering firm said this week.
I have charted that prediction below. The figures are the average yearly production.
The new Opec Monthly Oil Market Report is out with the March OPEC crude only production data. OPEC crude only fell by 626 kb/d and that was after February production was revised up by 121 kb/d. Big changes were Iraq, down 288 kb/d after February was revised up by 84 kb/d. Angola was down 154 kb/d.
Iraq is back to the same levels it reached in September of 2012. But Iraq is scheduled to increase production. West Qurna-2 is starting to ramp up. It is supposed to be producing 400 kb/d by the end of the year. I really doubt that it will get to those levels by then but it will definitely add to Iraqi production.
Folks here know that I like to post charts created from oil production data. But there has been a dearth of data lately. But not to worry, the data should start coming fast and furious later this week. However in the meantime I decided post a little about what the EIA expects in the future. They published the below comments and chart April 7, 2014. Bold mine.
Petroleum & Other Liquids
In the Annual Energy Outlook 2014 (AEO2014) Reference case, crude oil* production rises from 6.5 million barrels per day (MMbbl/d) in 2012 to 9.6 MMbbl/d before 2020, a production level not seen since 1970. Tight oil production growth accounts for 81% of this increase, and sees its share of national crude oil production grow from 35% in 2012 to 50% in 2019. In the High Oil and Gas case, U.S. crude oil production reaches 11.3 MMbbl/d in 2019 and reaches 13.3 MMbbl/d in the mid-2030s.
Under the Reference case, the import share of U.S. petroleum and other liquid fuels falls to about 25% during the last half of the current decade before rising again to 32% by 2040. In comparison, the High Oil and Gas Resource case projects that net U.S. oil imports will continue to decline through the mid-2030s and remain at or near zero between 2035 and 2040.
In the High Oil and Gas Resource case, tight oil plays an even more prominent role in driving national production growth, accounting for nearly two-thirds of total U.S. production by 2035, versus less than half of total U.S. production in the Reference case. Tight oil development is still at an early stage, and the outlook is highly uncertain. In EIA’s view, there is more upside potential for greater gains in production than downside potential for lower production levels. The High Oil and Gas Resource case assumes improvements in tight oil production technology beyond those in the Reference case, as well as higher well productivity rates.
Other assumptions reflected in the High Resource case include:
- Identification of additional tight oil resources
- 50% higher Estimated Ultimate Recovery (EUR) for tight/shale oil and natural gas wells
- 50% lower well spacing per acre for tight/shale oil and natural gas wells, with diminishing EUR for closely-spaced wells
- A 1% annual increase in the EURs for tight/shale oil and natural gas wells reflecting both abundant resources and technology advances
- Additional resources in Alaska and Lower 48 offshore fields