There are no two better fields in the Williston Basin for middle Bakken results than Parshall and Sanish. Parshall and Sanish fields are the focal point of EOG Resources' (EOG) and Whiting's (WLL) Bakken plays. EOG and Whiting were some of the earliest operators; this kept acreage costs down but also provided its pick of the best leaseholds. These two fields have seen more development than any other area of the Bakken. All have very good results, but both have a different history. Geology is not much different, except the depth of the middle Bakken and Sanish Sands.
The Three Forks is also shallower than around the Nesson Anticline. Shale thickness seems consistent in both the middle Bakken and Three Forks. The isopach below shows Bakken thickness of over 120 feet. Keep in mind thicker shale does not necessarily mean better EURs; it could provide a larger number of locations. This is evident in the picture below.
Whiting believes it can maintain seven locations per mile in the Sanish Field. The lower Bakken shale is extremely thick in both the Sanish and Parshall fields. It will maintain only three in the upper Three Forks. The Hidden Bench prospect is very interesting as it plans to drill eight locations in the middle Bakken, but this probably has to do with the Bakken Silt being thicker in this area. The upper Three Forks could be a big deal in this leasehold as it plans seven locations. It is twice as thick as in Mountrail County. The Pronghorn Sands may have something to do with this as well, but that is a guess on my part. Obviously, the Bakken is the focus in both Parshall and Sanish. Below is a Bakken isopach.
The Three Forks is comprised of two to four layers or benches of shale. The Three Forks has seen less development than the middle Bakken. EURs of the Three Forks in Mountrail County have lagged other areas. Northeast McKenzie County's Three Forks' locations have been the best in play, but there have been excellent Pronghorn Sands results in Billings and Stark counties. As seen above, the first bench of the Three Forks is somewhat thin compared to McKenzie County. Below is a Three Forks' map providing shale thickness.
The thickest shale is found in northwest Dunn and southeast McKenzie. Mountrail County looks promising at an approximate 225 feet. Shale thickness isn't the issue here, as Parshall Field produces less natural gas and exhibits lower pressure than northeast McKenzie County. It is also not as deep. Both should affect IP rates and EURs in a negative manner.
With respect to well design, these companies couldn't be more different. EOG used mainly short laterals with tight stages and large amounts of water and proppant. EOG has kept its wells on a very tight choke, but has opened its wells up some in 2012 and 2013. It has kept its costs down by self sourcing sand, and being very good at cutting costs. It was also the first operator to rail Bakken crude to St. James for LLS pricing. This significantly increased crude revenues, obtaining LLS pricing. Whiting uses long laterals with longer stages and smaller amounts of water and proppant. It has used a middle of the road choke size that inflates IP rates early with depletion being a little higher. EOG has been able to use a better well design and keep costs lower, while Whiting has kept costs in check by using less sand and water. Whiting and EOG have been able to keep costs low in these prospective fields.
EOG started developing the Parshall Field at around the same time as Whiting started working the Sanish. The big difference has to do with the amount of wells turned to sales. EOG completed 22 wells in 2006 and 2007. One of these wells is on pace to produce revenues over $100 million. Below is the Parshall well design over that specific timeframe.
|Well||Lateral Ft.||Water Bbls.||Proppant Lbs.||30-Day IP Bo/d||90-Day IP Bo/d||180-Day IP Bo/d|
Some of the above wells are missing data on water and proppant. Water, proppant and stages were not documented by most operators this early. This lack of data creates some issues, especially with respect to stage length. This may be one of the most important factors, as it improves source rock stimulation.
As a comparison, I have produced a table of Whiting's well results in the Sanish Field from 2006 to 2008. I could not generate enough data to produce a good average number with just 2007. This is important as EOG paved the way for other operators, and its results are twelve months earlier than Whiting's. I think this gives Whiting a little bit of an advantage as it was able to see what EOG was doing for an additional year. Below I have provided Whiting's well design and results for this specific timeframe. It produced 26 results compared to EOG's 22.
|Whiting's Sanish Field Well Design 2006-2008|
|Well||Lateral Ft.||Stages||Water Bbls.||Proppant Lbs.||30-Day IP Bo/d||90-Day IP Bo/d||180-Day IP B/od|
The above tables show like numbers for both water and proppant. EOG used a much better design with short laterals throughout. Whiting did have a couple of early wells that were quite low in production. This did hurt its average, as one well produced a 180-Day IP rate of 42 Bo/d. Whiting almost immediately moved to long laterals, which did improve its total EURs per well. IP rates of EOG's short laterals are better than Whiting's long laterals. EOG used twice the water and proppant per foot, but was able to produce more from less. The water and proppant amounts did better EOG's production, but it would seem source rock stimulation is the key to overall long-term production. It would seem EOG has found a good balance between stimulation, water and proppant usage. EOG's cumulative production is listed below. As stated in earlier articles, EOG's Parshall Field has produced more of the top 20 cumulative oil producers than any other operator.
|Well||Crude||Crude Revenues||Gas||Gas Revenues||Total Revenues||Days|
The above results are incredible. Using $90/Bbl crude and $4/Mcf, we see significant earnings in Parshall Field. The average well produced over $35 million in revenues. Granted, the gas lines may not have been in, and oil prices did sink during "The Great Recession," but I had to use a set price for comparison. Its wells have produced a little over five and a half years. This leaves another 30 to 35 years of production. Depending on the model used, we could see these revenues double over the life of all these wells. This would bring the average to over $70 million/well. I would guess these wells will not model like current completions. Most of these wells used no ceramic proppant. Given the depth and pressure, we could see the sand crushed under the weight of the formation. This would shut off the resource to the well. There is a chance that EOG's numbers outperform due to where it drilled middle Bakken wells. Most of its wells were drilled diagonally through each mile. This could be the best area of the shale to drill and complete, but it makes pad drilling a little worrisome. Whiting did a nice job of planning ahead so it could infill easier, with less worry about communication between wells. Below I have provided the cumulative production for Whiting's Sanish wells.
|Whiting's Cumulative Production|
|Well||Crude||Crude Revenues||Gas||Gas Revenues||Total Revenues||Days|
Whiting's wells produced a little over a year and three months less than EOG's. Average revenues were better by a little less than $2 million. It did this with slightly less water and proppant per well. The differences aren't seen until we break down design and production per foot of lateral.
|Operator||Water Bbls/Ft.||Proppant Lbs./Ft.||180-Day Production Bbls./Ft.|
The results were really surprising, as well design does seem to factor in short and long term results. These two fields are right next to each other, sharing the eastern Sanish border with the western Parshall border. Although geology could differ significantly from one mile to the next, it doesn't seem to be the main factor for the difference in these results. The results indicate short laterals produce better source rock stimulation. This produces more and better fractures. This followed by more water and proppant per foot will not only increase short-term, but also long-term production. Even more interesting is the percentage of increase in production per foot when compared to water and proppant per foot. EOG used 215% more water per foot than Whiting. It also used 221% more proppant per foot. This resulted in an increase of 223% of total barrels of crude produced per foot at 180 days. This suggests a correlation in the percentage of returns from water and proppant to production.
In summary, it is my belief that geology is the predominant factor in developing a model for production in the Bakken/Three Forks. That said, the best middle Bakken acreage is in southwestern Mountrail County. The Sanish and Parshall fields seem to have a dominant geology, as do Alger and Ross fields in the same area. Companies like Statoil (STO) and Hess (HES) have significant leaseholds in Alger and Ross, and have had their best results in those specific areas. This is obvious in other areas as well, and the reason QEP Resources (QEP) paid top dollar to get into Grail Field. Halcon (HK) also paid to get Petro-Hunt's Fort Berthold acreage, while Kodiak (KOG) bought Liberty. All of these areas have out-produced neighboring fields and will probably continue to do so. I am not saying that I believe Whiting or EOG Resources will be purchased; only that operators will pay a significant price per acre to get into that specific geology. Geology can be manipulated through well design. EOG continues to dump three times the proppant/foot in the Bakken and Eagle Ford. This has produced some of the best completions in 2012 and 2013. It has been replicated in southwest Mountrail, northeast McKenzie and western Williams counties. Kodiak purchased Liberty Resources for its well results in western Williams and northern McKenzie acreage. Liberty had similar results to EOG in western Williams, by using three times the water. I would guess the best areas have much better natural fracturing, but an operator still needs to properly stimulate the source rock to garner those resources.
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.