I recently covered the top Bakken oil producing wells. Since these wells are ranked on cumulative production, many have been on line for over five years. These wells varied in design with large differences in barrels of oil equivalent. Geology also plays a part further complicating results. In a perfect world these variables would be constant, and there would be little difficulty in gauging an operator's success. It is my contention that northeast McKenzie County has the geology to out produce Mountrail County. This coupled with better well design should produce results as good as those in Parshall Field. Improvements are better source rock stimulation, and increased amounts of water and proppant.
2012 was a very big year for the Bakken. Drilling and completion techniques have improved dramatically. This has decreased depletion rates, and is improving EURs. This is important, as the bulk of the best wells were back in 2008. With the exception of Parshall and Sanish field, 2009 was a poor year. At this time, operators used a deficient well design with limited amounts of water and proppant. Most were using sand, which crushed under the weight of formation. This allowed the fractures to close shutting off resource the to well. Things began to change in 2010. These companies began using more hydraulic horsepower and more stages. This combination optimized fracking, creating longer and wider fractures. Companies like Brigham began using much larger amounts of water and proppant. It also used ceramic proppant with good success. The table below lists some of its better well results.
Brigham's Best Early Wells
The above wells had excellent IP rates (24 hours). It is important to remember a big number the first day does not guarantee future production. 24-Hour IP rates can be skewed through manipulation of well design. There are several variables to focus on, such as the gas to oil ratio. Wells with higher percentage of gas production will have higher well pressures and produce better IP rates. The above wells produced higher IP rates due to a larger choke. A tighter choke restricts resource from being allowed out of the well. This keeps well pressures high and decreases IP rates. Using a bigger choke will allow more resource to be garnered in a shorter period of time, but this causes a rapid decrease in well pressure. Brigham operates under the assertion that maintaining well pressure is not important to longer term production. There are other companies like Oasis (NYSE:OAS) that also do this, and at this point there is little to prove otherwise in liquids dominated wells.
Looking at Brigham's results, its well design was ahead of its competition. Its high IP rates are not just generated due to the choke as other variables are much more important. Its understood large amounts of water per foot is very important. In 2010 and 2011, it was using much more water, proppant and stages than other Bakken operators. A large percentage of its proppant is ceramic. This is very important in the deeper areas of the play. Operators like Kodiak (NYSE:KOG) and Helis have shown longer term production rates improve significantly using ceramic proppant.
Below I listed some of the better wells in 2012 and 2013. The first three are located in northeast McKenzie County where a much larger percentage of resource is gas. The fourth well is in Parshall Field, operated by EOG. This well's first year of production places it as the third best Bakken well in the history of the play.
2012-2013 Best Bakken Wells
The above wells are excellent, but there is a big difference in longer term production. Judged by its IP rate the Conoco (NYSE:COP) well 20636 is a monster. Production per foot is unreal. Keep in mind this well is in Charlson Field, the same field PetroHunt drilled the top well in the history of the Bakken/Three Forks. This well was also a very short lateral under 4000 feet.
To show how little 24-Hour IP rates have to do with modeling EURs, I have broken down its production. The table below lists that data.
Longer Term IP Rates
|Well||Operator||IP Rate||90-Day IP||180-Day IP||360-Day IP|
Every one of these wells except 21239 have 24-Hour IP rates of well over 4000 barrels of oil per day. All four of the Statoil wells were drilled before Brigham was purchased. These wells are located in the Ross area of Mountrail County. This acreage is not as good as Parshall and Sanish Field, but it is a close second. These wells produce very little natural gas which is only about 3% of the production mix.
There has been some very good press on the Conoco well. It currently has the top IP rate in the Bakken for oil. Its well file paints a different picture as its 90-Day IP rate drops significantly. Given the length of lateral, this is still a good well in production per foot, but the well is by no means a top Bakken well. Well 20636 has had some production issues as well, so well design does factor into the higher depletion rate. This and the Statoil wells are used by the bears to down play the Bakken's significance. The depletion rates are quite high, even though the Statoil wells are considered to be very good producers.
The last well in the above table was included for comparison only. Its 24-Hour IP rate is just 1315 Bo/d. By choking back production EOG is not able to monetize the resource as quickly, but it shows control of depletion at a very slow rate. This well was still producing 800 bbls. of oil per day after one year of production. Not only is this a top well, my model shows it is the second best producer in the Bakken as of its 270-Day IP rate. Since this well has depleted at a slower rate than those top wells, it is possible it could be far better than all of its wells in Parshall Field.
I get a significant number of emails with questions about well results and why it is better or worse than neighboring wells. These are very tough questions because there are some variables that a well file cannot qualify. An operator can miss the sweet spot when drilling. The completion style may not be optimal. Geology can change quickly from one mile to the next, which can also affect results. These are just a few of the possibilities, but now that the operators are doing a more consistent job we are getting some transparency. Variables we can track are proppant, water, choke, stages and lateral length. Since laterals vary significantly, it is difficult to know which wells were out performers. If two wells are drilled and completed in the same general area and one models to an EUR of 400 MBoe and the other 600 MBoe, we would presume the latter was better. This would not be the case if the first well was a 5000 foot lateral and the second 10000. The longer lateral would have produced only 75% of the resource per foot of the short lateral. The table below breaks down these wells into feet.
Well Design and Results/Foot
This data show how well each company is drilling and completing each foot of the lateral as an average. Well 21239 is where well design may be going. EOG is using a huge amount of water and proppant. The combination seems to be working real well in the Eagle Ford. What may be the most important is stage length. While most operators are using 300 feet as an average, EOG is working under 200. By using shorter laterals and stages an operator can get the most out of the hydraulic horsepower used from its pump trucks. This produces better fracturing of the source rock. Plenty of proppant and water is needed to fill in these fractures. The better this is done, the more production garnered from the stimulation. This should also decrease depletion. Well 21239 used far more water and proppant. In concert with shorter stages produced 3.6 more barrels of oil per foot than the second best result after 180 days of production. Keep in mind geology can play a bigger part than well design. Whiting's wells 20589 and 22361 are great wells. Both of these were done using amounts of water and proppant below the industry average. Whiting generally uses less which has kept its well costs low. This has also hurt production, but has helped to keep its Sanish Field costs down to $6.5 million.
In summary, the middle Bakken continues to produce better well results. At one time, we believed that Parshall and Sanish fields were by far the best areas in North Dakota. New results show northeast McKenzie County may have more upside. Not only are the EURs higher in this area, but there is added Three Forks upside. Helis has proven the Three Forks can be as good, if not better. It also has a much larger number of possible locations. Better well design also contributes as operators use more stages, water and proppant. The best ways to play this are operators levered to this area. Kodiak is the best way to play this area, as it is a Bakken pure play with a large portion of its acreage here. The larger amounts of sand used will be beneficial to U.S. Silica (NYSE:SLCA) and Hi-Crush Partners (NYSE:HCLP).
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. Fracwater Solutions L.L.C. engages in industrial water solutions for oil and gas companies in North Dakota. This includes constructing water depots, pipelines and disposal wells. It also provides 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. More of my articles and other pertinent information on the oil and gas sector, go to shaleexperts.com.