There has been news of some of the bigger players moving rigs out of the Bakken and into other areas that have shorter payback times. Several variables are affecting the Bakken players such as rising costs and lower realized pricing of crude. There is no doubt areas like the Eagle Ford (condensate window) are more productive than the Bakken, but there are more reasons for the moving of rigs by companies like EOG Resources (NYSE:EOG) and Newfield (NYSE:NFX).
When comparing the Bakken to the Eagle Ford, there are reasons to believe Bakken estimates may be quite low from a long term perspective. When an oil producer begins de-risking its acreage, it will drill and complete wells one at a time in different areas until that acreage is held by production. Once this is done, the oil company has the luxury to work its acreage as it sees fit, and in most cases the best acreage will see the bulk of company cap ex. Now that many of the Bakken players have de-risked the majority of its acreage, we are beginning to see a ramp in pad drilling and the number of wells drilled per 640 acres. Well spacing in the Eagle Ford is much tighter than that of the Bakken, but I think we may find that the Bakken/Three Forks may provide spacing in some areas as tight or tighter than that of the Eagle Ford.
Oil producers have been working leaseholds hard to get acreage held by production. After this is accomplished, companies can drill locations in any manner they deem appropriate, and this should create changes in the Bakken shale for 2012. We have already seen some of these changes by the more progressive companies, but now it should be more wide spread.
Bakken areas not as good with respect to production may be put on hold, or in the case of Newfield, who sold 23000 net acres for $276 million to pay for the development of better acreage. Bakken wells have some of the best estimated ultimate recoveries of unconventional oil plays in the United States, but costs are rising putting pressure on the bottom line. Pad drilling can decrease costs significantly, averaging a savings of $500,000/well.
Savings from decreased fraccing days, equipment reduction in mobilization, etc. This is achieved through simultaneous fraccing and plug and perf operations. Zipper fracs also decrease costs through shorter fraccing times. A three well zipper frac using 38 stages decreases time from a one well frac of over 10 days, to just a little over four days. Pad drilling could also shed some light on well spacing.
Oil producers have been busy drilling, completing and documenting results. Most believe the better part of north McKenzie, south Williams, west Mountrail, and northwest Dunn are all very good. This area is believed by most to be able to produce four middle Bakken and four Three Forks wells on 1280 acre spacing. Brigham was the first to come out with an assumption of five and a half middle Bakken and four Three Forks with the use of density drilling. Brigham had also thought it could produce four and a half middle Bakken, with four and a half upper Three Forks wells per location.
These types of estimates seem to only be the beginning as companies continue to work from pads and better frac shale to get the most from each acre. Well spacing can be as significant as estimated ultimate recoveries, well costs, and etc. When looking at an acreage, we want to figure the amount of recoverable oil in the ground. An easy way to do this is to take the estimated ultimate recovery (EUR) and multiply by the number locations. Remember to keep in mind the lateral length, as 640 acre laterals, will not produce as much as 1280 acre. There are a few other variables such as the number of stages, and size of choke that will skew these numbers somewhat, so also keep this in mind.
To best show differences based on well spacing I will compare the Eagle Ford, and Bakken. Marathon (NYSE:MRO) is currently working both plays, and is very descriptive as to its estimates. The Eagle Ford shale has an interesting geology with high carbon content that outcrops in a northeast to southwest trending through central Texas. It is 50 miles wide and 400 miles long. It is best identified in three parts, or windows, that also run from the northeast to southwest.
Unlike the Bakken that has very high percentages of oil throughout, the Eagle Ford produces differently from each window. To the southeast is the gas window, and as the name suggests this play is mainly natural gas. It is also the deepest part of the play reaching depths of 14000 feet. The northwestern section is referred to as the oil window. This section produces mostly oil and is very shallow. The Eagle Ford is being drilled at depths around 4000 feet. Sandwiched between the oil and gas windows is the Condensate or "wet gas" window. The Condensate window is much like the other two windows, except it produces a lot of wet and rich gas. A significant amount of oil is also garnered here.
The high liquids content in the central portion of the Eagle Ford shale is economic. Much of these liquids are natural gas condensate, which is low density mixture of hydrocarbon liquids found in many natural gas fields. This condenses from raw natural gas when the temperature is reduced below the hydrocarbon dew point temperature of the raw gas. It should be noted natural gas wells can produce condensate as a by product, but condensate wells produce raw natural gas along with natural gas liquids. The condensing of natural gas increases its energy density and increasing its value. Liquefied natural gas can be transported via pipeline, or by ship all over the world.
These variables are why natural gas liquids have parity to oil pricing, and in turn are much more valuable than dry gas. Natural gas liquids have held pricing much better than gas, given the ability to transport. Using $85 West Texas Intermediate (WTI) pricing and $4.50 natural gas pricing, this window has an un-discounted payout of 1.9 years using a 5000 foot lateral. Gross well costs are $7.9 million/well. It has an EUR of 965 Mboe. Acre spacing of 80 to 160 acres is expected.
To the west of the condensate window is the volatile oil window. It has an un-discounted payout of 3 years using a 5000 foot lateral. Well costs are between $7.7 and $8.1 million and have EURs of 645 Mboe. The black oil window has an un-discounted payout of 4.7 years with gross well costs of $7.9 million. EURs of 445 Mboe are expected in the most western part of the Eagle Ford play.
EOG Resources paints a different picture of the Eagle Ford. It is using a 4,000 foot lateral and has down-spaced this play between 65 and 90 acre spacing from the initial 135 acres. EOG expects 450 Mboe NAR/well. It expects well costs of $5.5 million. EOG states its peers are realizing completed well costs of $7 million.
Anadarko Petroleum (NYSE:APC) has 100 acre spacing of its 400,000 gross Eagle Ford acres. It has well costs of $5.8 million and EURs of 450 Mboe. The Eagle Ford pay zone is 200 to 300 feet thick. Due to this thickness well spacing in much tighter than that of the Bakken that at its thickest point is roughly 90 feet. I currently believe the Eagle Ford condensate and oil windows support 80 acre spacing for which an average EUR of 650 Mboe could be attained at a well cost of $5.5 to $7 million depending on operator (5000 foot lateral). I would like to point out that some of the recent EOG wells are significantly better than this (Mitchell Unit) and have EURs closer to 900 or 1000 Mboe. It should also be noted that EOG is currently out producing it competition with respect to 30-day initial production rates over 2 to 1 in barrels of oil equivalent/day.
It is obvious that a certain section of the Eagle Ford is the best acreage in the lower 48, but we need to look at how this compares with some of the areas in the Bakken. Marathon has an un-discounted payback of 4.3 years in its southeast Mountrail County acreage. This is based on an EUR of 570 Mboe, a 9,000 foot lateral, and 420 acre spacing. Well costs should average $8.6 million, and it is going to 30 stage fracs this year.
These numbers are very conservative, but Marathon is just starting to get comfortable in the Bakken. In the Bakken EOG is currently using 320 acre spacing in its core Mountrail County leasehold. EOG's model provides EURs of 550 Mboe using short laterals (approximately 5000 ft.) in Parshall Field and surrounding areas. More recently EOG is down spacing in its Bakken core position to 160 acres from 320.
Before being sold to Statoil (NYSE:STO), Brigham had well costs of $8.9 million. It had an average EUR of 600 Mboe and an un-discounted payback of 1.9 years. Although it has an average EUR of 600 Mboe, it had several wells in the 800 to 900 Mboe range. Brigham predominantly does 2 mile (10000 ft.) laterals. As stated earlier EOG is down spacing to 160 acre spacing, while Brigham has already begun its 5.5 Bakken wells/section or 120 acre spacing. Using this on both the middle Bakken and upper Three Forks would provide 11 wells on 640 acres.
Continental (NYSE:CLR) has Bakken EURs of 603 Mboe. Utilizing pad drilling, well costs are $7.2 million on a 2 mile lateral. Continental has already recorded two commercial second bench Three Forks wells. This could add a new pay zone in North Dakota, with a possible four additional wells. At this time we are unsure how far this is commercial, but Continental has said this shale has been somewhat consistent while the last two benches have not. The Three Forks offers an additional 180 to 270 feet of source rock thickness.
As these Bakken names are working to down space leaseholds, we could see some significant changes. Hess (NYSE:HES) in Alger Field currently has six confidential wells at NWSW 16-156-93. This is rumored to be a $100 million 12-well pad. These twelve wells will probably be 6 middle Bakken and 6 upper Three Forks. On top of this, there is a possibility lower Three Forks wells could also be drilled. If in line with the first bench of the Three Forks we could at least see an additional 4 wells, which would provide 40 acre well spacing.
Given this is Alger Field, it would not be inconceivable that the middle Bakken wells will produce 900 Mboe, and the upper Three Forks 700 Mboe, and the second bench at 500 Mboe. If this is the case, and it is just an estimate as I do not have enough information yet, this pad could produce 11 million 600,000 barrels of oil equivalent. But again, it is just an estimate.
Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.