EOG Resources (EOG) is changing the way it is working the Bakken. The Eagle Ford is its flagship, followed by the Bakken. The Permian was replaced as its number 2 play after NGL prices pulled back. This wasn't the only reason, as EOG was the first to rail Bakken Light to Louisiana. Its ability to get LLS pricing has changed the dynamics of Bakken price realizations. In the most recent quarter, EOG had a realized crude price of $10.52 above WTI. This has worked so well, EOG only utilizes a very small percentage of production in pipeline capacity. Other Bakken operators have begun railing crude. The rails will be a big part of Bakken crude transport for many years and it all started with EOG.
Over the past year, EOG has implemented a new completion design. It was first used in the Eagle Ford and Permian, and now it has found its way to North Dakota. In the Eagle Ford, EOG has used this and has a large number of short laterals with 24-Hour IP rates north of 3000 Bo/d. Its best completion, the Burrow Unit #2 produced 6331 Bo/d. In order to increase crude production it has not focused on long fracs but those that increase the surface area around the well bore. Essentially, it wants better fracs near as opposed to farther away as it allows the crude to flow in a radius around the well bore.
EOG has two areas of focus in North Dakota. The first is its core Parshall Field. The resource mix is 92% oil, 6% NGLs, and 2% gas. The second is its Antelope Prospect of northeast McKenzie County. This area produces 78% oil, 11% NGLs and 11% natural gas. The Antelope produces higher EURs, but the increased gas content makes these areas less economic. It plans to drill 46 wells in these areas, down spacing to 160 acres. EOG's new completion design has improved production by 30% to 70%.
In a recent article, I went over EOG's newer Bakken completions and how it has been modifying well design for better recoveries. It differs greatly from the Bakken average of a 9000 foot 30 stage laterals using 60000 barrels of water and 3 million pounds of proppant. I have listed a few of EOG's wells that have this completion design below.
EOG's New Bakken Well Design
The above well design is not cheap. The amounts of water and proppant are some of the largest in the United States. Below are other significant wells by EOG.
Other Significant EOG wells
The production of these wells is important to gauge how effective the well design is. I have broken down each well into initial production rates.
EOG Initial Production and Cumulative Production
|Well||90-Day IP||180-Day IP||270-Day IP||Total Oil|
Lateral length is important. Wells 21689 and 20578 are both short laterals. From a production per foot standpoint, these wells are the best in this article as of 90 days of production. More importantly, these were both completed in September of 2012. Of the best Bakken wells to date, a large number are short laterals. Most of these are EOG's Austin wells in Parshall Field. Five of the top 10 cumulative oil producers in North Dakota have the Austin name. The table below can be used as a comparison, as I have selected some of the very best wells completed by individual operators in the Bakken. Some of these wells are the very top producers.
Top Bakken Well Design
The above wells are all very good, as are the operators. It is interesting that each well has its own unique style. EOG and Newfield both completed short laterals. Although most operators have moved to long laterals, source rock stimulation is much better with a shorter leg. The Newfield well has very tight stages of approximately 203 feet. EOG used the tightest choke, which proved effective in flattening the depletion curve. Statoil, uses a wide open choke. This improves 24-hour IP rates, but depletion is greater.
Top Initial and Cumulative Production
|Well||90-Day IP||180-Day IP||270-Day IP||Total||Date|
Wells 16991 and 17092 are in the top 10 for cumulative oil production in the Bakken. The reason I used these wells was for a comparison. EOG's well 21239 has a 270-Day IP rate greater than both. This is the third highest 270-Day IP rate in the history of the Bakken. The 90-Day IP rate was not that impressive, but depletion is. Production depleted less than 3% from the first 90 to 270 days of production.
In summary, EOG may be using its Eagle Ford and Permian completion technologies in the Bakken. It is difficult to know for sure how it accomplishes this, but it has most of the best Eagle Ford wells, and recently figured out how to improve in the Leonard. This is important from a production standpoint. Its new completion techniques in the Eagle Ford have produced significantly more resource. An example is its Baker-DeForest Unit. EOG completed 5 wells in August of last year. The total crude produced from August to December is 879338 barrels. In its most recent quarterly report, EOG had a $98.72 realized oil/condensate price. Using this price, EOG has already received oil revenues of $86.8 million. In August alone it produced 337717 barrels of oil. Its average well cost is $6 million. Total Baker-Deforest Unit well costs are $30 million. August oil revenues were over three million greater than total costs. Remember, this does not include revenues from NGLs and natural gas. EOG used approximately 8.5 million pounds of sand per Eagle Ford Well. I believe EOG used the same well design on its Bakken well 21239. It produced a total of 330762 barrels since March of 2012.
I believe EOG has figured out how to better stimulate the source rock closer to the well bore. Most operators have tried to improve fractures further away. This poses a problem for proppant to travel greater distances. With more fracture surface area close by, the sand can be packed in deep providing a less restrictive zone for crude to flow. This would provide the reason for the very large amounts of sand. If this is true, even average acreage could see payback times in less than a year. Only time will tell, but if EOG can produce these results, so can other operators. This completion technology is now a proven technique. It has worked for EOG in three of the best unconventional basins in the United States. I estimate it will increase EOG production growth in the Bakken for 2013 by 50%. Currently it only benefits EOG, but companies like Kodiak Oil and Gas or Oasis (OAS) could see production growth of 30% to 70% if and when it adopts this technique. This is the type of technology that could change the economics of unconventional oil. Another way to play this is through U.S. Silica (SLCA). Increased usage of sand proppants would directly improve its business.
Additional disclosure: This is not a buy recommendation. The projections or other information regarding the likelihood of various investment outcomes are hypothetical in nature, are not guaranteed for accuracy or completeness, do not reflect actual investment results, do not take in consideration commissions, margin interest and other costs, and are not guarantees of future results. All investments involve risk, losses may exceed the principal invested, and the past performance of a security, industry, sector, market, or financial product does not guarantee future results or returns. For more articles like this check out my website at shaleexperts.com. Michael Filloon is a Director at Fracwater Solutions L.L.C. We engage in industrial water solutions for oil and gas companies in North Dakota. This includes constructing water depots, pipelines and disposal wells. We also provide contracting services for all types of construction at well sites. Other services include soil remediation. Please contact me via email if you are interested in working with us. For other, more of my articles check out shaleexperts.com.