In part one of this series, I addressed some issues with the article Is Shale Oil Headed for a Run with "The Red Queen"? Its author, Rune Likvern, has a bearish view of Bakken production. He believes Bakken production is close to hitting a plateau. The Red Queen tries to paint a Bakken picture that has very few great wells with large initial production or IP rates. It states most wells are marginal at best, but the best wells are in press releases. I am unsure of the logic here, as Wall Street follows the Williston Basin closely. If the only wells publicized had high IP rates, the market would have abandoned these stocks a long time ago. These conspiracy theories are spoken of a lot, but have little backing as the truth is unconventional resource is the key to the future. If it were deemed the Williston Basin was not economic, we would not see the best in the business working these acres. Exxon (XOM), Conoco (COP) and Occidental (OXY) are just a few big players increasing their stake in North Dakota.
The Red Queen article makes a case for a plateau in Bakken production. Mr. Likvern believes depletion rates will soon outpace new production. This is an interesting concept as horizontal wells deplete at high rates. This topic is confusing, so this information is rarely exposed as invalid. Unconventional locations do not deplete at the same rate throughout well life. The fact is the depletion curve flattens after a few years. There are a significant number of production models used to show depletion. Every oil producer has its own model. These are influenced by location, operator, completion style, etc. All said, most operate on the same premise.
Oasis (OAS) provides a general production model for its Bakken wells on page 26 of its company presentation. It states a well with a 7-day IP rate of 704 Boe/d will deplete to 100 Boe/d after three years of production. This is a significant number, but 9 years later, this production number decreases to 60 Boe/d. By the Oasis model, this well has an estimated ultimate recovery, or EUR, of 600 MBoe. Most of these wells will produce half of their resources in the first 5.5 years. Oasis has an average well cost of $8.8 million. If we do not account for natural gas or natural gas liquids and presume the well is 90% oil, 270,000 barrels of oil will be produced in 5.5 years. When looking at production models, do not focus on the IP rate. This number can be skewed by choke size, so the curve is what is important. After a large initial decline, the well will slow to an approximate 8% annual depletion rate.
Whiting (WLL) has modeled several areas of its Williston Basin acreage. Its middle Bakken Sanish model covers an EUR range of 950 MBoe to 450 MBoe. Well costs are $6.5 million in this area. Whiting's lower well costs are due to a completion design using less water and proppant. These wells deplete to 100 Boe/d from 30 to 84 months depending on the well's EUR. Upper Three Forks wells in the Sanish have EURs of 400 MBoe. After 15 years of production a 950 MBoe EUR well will be producing 50 Boe/d, and a 450 EUR well will be at 25 Boe/d.
EURs for Whiting wells outside the Sanish, including the middle Bakken, upper Three Forks and Pronghorn, range from 350 MBoe to 600 MBoe. Pronghorn wells will have an average cost of $6.5 million. Locations outside the Pronghorn have slightly higher costs at $7 million. Last year, Whiting's costs had swelled between $8.5 and$9 million. The new found savings per well is partially due to pad drilling, sliding sleeves, and reductions in overall completion costs. Other companies are spending this savings on a beef up well design, but Whiting continues to stay with its current program. Its current wells are very profitable as its average Sanish middle Bakken well will produce 700 MBoe. Keep in mind, these numbers do not include land charges and corporate G&A. Watch how these wells produce going forward, as Whiting should have a higher depletion rate going forward than its competitors.
Magnum Hunter (MHR) has modeled its Divide County wells which are operated by Samson. The middle Bakken in Divide has a shallow depth, which produces lower pressure, and is cheaper to drill. Average well costs of $7 million are seen here, with EURs of 400 MBo (does not include natural gas and NGLs). Recent completions have had significant improvements in production, and should see increases in EURs. Its Thomte well was modeled to a much higher EUR than the 400 MBo used on older locations. It will take time to see the effect on production, but estimates should continue to increase.
Halcon (HK) recently purchased GeoResources and now has acreage in western Williams County. This area is interesting, as most wells report low IP rates. Halcon expects EURs of 333 MBoe with 282,000 of those barrels being oil. Resolute (REN) is Halcon's non-operating partner in Williams County, and it models EURs of 400 to 333 MBoe. These models have IP rates in the 300 to 400 Boe/d range. Wells in this area deplete to 100 Bo/d in 18 months. Because these wells have very low pressure, there is a flat curve with respect to depletion. Well costs average $7.5 million.
QEP Resources (QEP) is very active in Fort Berthold. This acreage is some of the best in the Bakken, and QEP has done a very good job of showing why it paid $25,000/acre in the Helis deal. It believes the average Bakken/Three Forks well will produce EURs of 550 MBo. This is up from August, where it had this average at 500 MBo. This is figured only for barrels of oil and does not include natural gas and NGLs. QEP's model is much like the others in this article with a significant initial decline followed by a flattening in the depletion curve. Its average well cost is $9.5 million. Keep in mind that drilling on the reservation increases well costs on average $500,000/well. QEP wells have produced EURs in the 300 to 900 MBoe range, but its Helis acreage has opened everyone's eyes to new found potential. The premium for the acreage 12 miles west of QEP's core acreage was justified. In this article, I highlighted Helis's well results as being some of the best in the entire basin. The results of Helis's 24 Three Forks wells have been outstanding. In the table below, I have highlighted company EURs.
|EUR Range||Total Number of Wells|
These results show an improvement in well design has increased total resource recovery. More importantly, this is Three Forks production which has historically lagged middle Bakken results. Here are the Helis's middle Bakken results in the same core acreage.
|EUR Range||Total Number of Wells|
The information above shows how lucrative these wells are from a long-term production standpoint. What is difficult is using IP rates to figure out EURs as lateral length, choke size, the number of stages, volumes of water, proppant type and the amount used are just a few variables the can affect how a well produces. It is also important to factor in how deep the target formation is as the deeper the play, the more expensive it is to drill. Deeper wells also have greater pressure which returns more resource over a shorter period of time.
Some areas of the Bakken are not economic, but there is still a huge amount of inventory to drill through. Now that most operators have acreage held by production, pad drilling can start. This will reduce costs and time associated with drilling wells in specific areas. The table below contrasts wells by area. This information shows differences in profitability for specific areas in the Bakken.
|Location||Cost||EUR||One Year Total Production||5.5 Year Total Production||% Oil||1 Year Oil Total Revenues||5.5 Year Oil Total Revenues||Total Oil Revenues|
|W. Williams||$7.5||400||76000||200000||87||$ 5289600||$13920000||$27840000|
|N. McKenzie||$9.5||700||129000||350000||90||$ 9288000||$25200000||$50400000|
The table above assumes $80 oil. Revenues do not include natural gas or natural gas liquids.
In conclusion, the Red Queen article stated an oil price of $80-$90/barrel was needed for Bakken wells to make commercial sense. Using an $80/barrel oil price we see that the majority of middle Bakken wells produce enough revenue to pay back costs in the first year of production. The author also made the mistake of not including natural gas, as he stated the potential contribution is marginal at $3/Mcf. It is obvious the author is not familiar with Bakken production as wells in NE McKenzie County can produce up to 11% NGLs. Using a $40/barrel price, in the first year revenues from NGLs are over $730,000. The author made another mistake in using what he believes to be the average Bakken well production for the first twelve months. I believe he found these average wells using old well information. Using current EURs, we see that average production numbers are far higher than those used in his research. Mr. Likvern also believes that Bakken well productivity is decreasing, and stated from 2010 to 2011 this has decreased by 25%. This could be from increased development of the upper Three Forks. This pay zone is less productive than the middle Bakken in the 20% to 25% range. Also, less productive areas are being drilled to get acreage held by production.
Mr. Likvern's conclusions are incorrect. Well costs are improving in the Bakken, and will continue to do so through 2012. Pad drilling, sliding sleeves, shorter drill times, and other efficiencies have all helped. Initial production rates and EURs are also increasing. More frac stages, water, proppant and better completions continue to push these numbers higher. This should continue going forward as oil producers are beginning pad drilling programs, and are able to increase production with fewer rigs while utilizing zipper fracs to decrease completion times. If you would like to see the future of the Bakken, just look at Helis's completions. The Thompson 1-29/32H well produced 262,916 barrels of oil in the first 366 days. If Helis can produce these types of results, I am sure other companies will be able to do this as well.
Additional disclosure: This is not a buy recommendation.*Lewis and Clark and the Pronghorn are prospective the Three Forks/Pronghorn and not the middle Bakken.