The increase in unconventional oil production in the U.S. provides an excellent opportunity for investment. The top and bottom lines of and oil and gas exploration and production companies provide cogent information to compare one company to the next. To truly understand these companies, one must understand the most important variable, which is well results. This can be a daunting process as unconventional production is a new technology. Hydraulic fracturing has been around for decades, but it hasn't been used as a basis for U.S. land oil production for very long. There is little data to compare, but we are starting to understand this process and how it affects production. Plays are considerably different. The Bakken has some of the highest costs due to its lack of infrastructure, difficult weather, and deep source rock. These costs are offset by large EURs heavily weighted to crude. Areas like the Mississippi Lime are the opposite. Very low well costs, production under 50% oil and much lower recoveries.
There are several things that make a great unconventional well. The first and most important is identifying the sweetest part of the source rock. Once there, the lateral is set to the expected length. This is rather tricky as laterals can be just about any length. A shorter lateral generally produces better per foot. This is due to the toe of the lateral being closer, so the pump truck can better use its hydraulic horsepower. A lateral also has a series of stages. Stages are a series of numerous reservoir intervals hydraulically stimulated in succession. The shorter the stage, the better the shale is fractured. This opens the well to a larger surface area of shale resource.
To prop open the fractures water, proppant is pushed into the fractures so resource can continue from the source rock and into the well. There are many different types of proppant. Sand is the cheapest, but crushes under higher pressures found in deeper wells. Ceramic coated sand is more expensive, but handles higher pressures. Ceramic proppant is the most expensive and can be used in the deepest pay zones. An operator must balance cost and optimal well design. An example is the amount of proppant used. It does no good to use more proppant than can be used to fill in fractures. The exact amount and type will maximize returns.
Optimal well design is accomplished by balancing these variables used in concert. Each operator uses its own recipe. Companies like Kodiak (KOG) and Triangle (TPLM) use the best technologies, and this tends to push up well costs. Companies like Whiting (WLL) focus on using less and keeping well costs low. We won't truly know which is the best until later in well life. At this time, we will know how wells deplete long term and if spending the extra cash was worth it.
Back in November of last year, I began covering a change EOG Resources (EOG) had made with respect to its completion work. I originally noticed this in the Eagle Ford, as it had the best results of any unconventional horizontal wells on land in the United States. Originally it was believed the Eagle Ford was that much better with respect to geology, but other operators in the area such as Magnum Hunter (MHR) and Penn Virginia (PVA) under performed in Gonzales County. The differences were quite large, as EOG wells had 90-day IP rates triple that of Magnum and Penn. When the data is compared on a production/foot basis, EOG's wells improve further.
What separates EOG from other operators is how it looks at source rock stimulation. Operators have historically thought the deeper fractures would produce the most resource as it intermingled with the existing fractures. EOG is focusing on creating fractures close to the horizontal leg. Not only would the pressure create more and better fractures, it could possibly increase the number of locations per square mile. This would reduce the chances of communication between wells. With fractures closer to the well bore, it is easier to get the water and proppant pushed deeper into the source rock. In essence, we will see more pressure from the pump trucks exerted over a shorter distance. This would increase the fractures per square foot. In response, more proppant and water would be needed per foot. Tighter stages would be beneficial as this would produce additional fracturing.
By using this technique, EOG found it needed more water and proppant per foot. These wells cost significantly more as EOG uses twice the stages, twice the water and three times the proppant of the average operator. EOG has done a great job of keeping well costs in check as it sources its own frac sand. EOG hasn't formally announced a big difference current well costs, but it is only using this design on some of its wells. Given the cost, EOG has focused this design on better areas of the Eagle Ford, Wolfcamp, and Bakken. EOG has now begun using this completion design in western Williams County, North Dakota. This acreage can be seen in the picture above labeled the Stateline/Diamond Point area. We already know this completion style works very well with respect to better acreage, and this article will show its affect on western Williams. Below are four EOG completions to date.
|Well||Choke||Lateral Ft.||Stages Ft.||Water Bbls.||Proppant Lbs.||30-Day IP Bo/d||90-Day IP Bo/d||180-Day IP Bo/d|
The table above provides EOG's new well design. These results are phenomenal considering the area. Well 20219 was a short lateral, so production per foot was still quite good. These wells have some of the largest concentrations of hydraulic horsepower per stage, proppant and water per foot. It has always done this, but continues to better well design. The question isn't how much it uses, but where this design will find maximum concentrations. The fourth well on the list did pull down the initial production averages as it was a short lateral. If removed, the 30-Day IP increases to 762 barrels of oil per day. The 90-Day increases to 572. EURs of these wells run between 650 and 750 MBoe. These are conservative estimates, as I believe these wells deplete at a much slower rate. Other operators estimate EURs from 300 MBoe to 400 MBoe in this area. Below I have listed EOG's 2011 and 2012 western Williams County wells using its old well design.
|Well||Choke||Lateral Ft.||Stages Ft.||Water Bbls.||Proppant Lbs.||30-Day IP Bo/d||90-Day IP Bo/d||180-Day IP Bo/d|
Before EOG began using its new well design, the above wells were the best in western Williams County. As you can see, the disparity in results from table one to table two are quite large. By comparing these tables, we see what is accomplished through better stimulation near the well bore. Since the fractures are closer, it allows for the water and proppant to travel deeper into the source rock. Using tighter stages allows for better stimulation as there is more pressure per square foot.
We don't truly see how good this well design is until it is compared to other operators. Squires is one of the largest and most active fields in the area. I chose this area due to several very good operators and a significant number of results for comparison. EOG Resources is also active and has results in the table above. Below are well design and results for operators in this field. These wells are listed in order by time frame to give an idea of how well design has changed for each operator.
|Well||Co.||Choke||Lateral Ft.||Stages Ft.|| |
|Proppant Lbs.||30-Day IP Bo/d||90-Day IP Bo/d||180-Day IP Bo/d|
The operators above use more water, proppant and stages per well than EOG's in table two. Normally this would produce better IP rates, but in this case it hasn't. The average EOG well is a shorter lateral, which is contributing to the results. Lateral lengths can vary significantly, which is the reason wells are better compared on a per foot basis. Look at the lowest producing wells above with respect to the 180-Day IP, wells with the longest stages produce much less oil. This occurs in the presence of large amounts of proppant and water. Tight stages could be the most important aspect of well design. If the pump trucks have a smaller surface area to stimulate, it will produce more and better fractures. As a comparison, the average well in 2012 used 300 foot stages. Below I am comparing these results independent of lateral length. EOG has reduced stage length to a little over 200 feet. The first is EOG's most recent completion style.
|Feet per Stage||Water per Foot||Proppant per Foot||180-Day Production per Foot|
|Table 1||214 Ft.||11.4 Bbls.||1023 Lbs.||9.5 Bbls.|
|Table 2||303 Ft.||6.3 Bbls.||451 Lbs.||6.5 Bbls.|
|Table 3||311 Ft.||6.8 Bbls.||375 Lbs.||4.2 Bbls.|
|CLR||417 Ft.||5.0 Bbls.||294 Lbs.|| |
|STO||263 Ft.||8.0 Bbls.||404 Lbs.||4.4 Bbls.|
|QEP||396 Ft.||5.2 Bbls.||366 Lbs.||3.9 Bbls.|
|OAS||395 Ft.||5.8 Bbls.||345 Lbs.||3.8 Bbls.|
EOG is able to better fracture the source rock, with shorter stages and focusing pressure close to the lateral. This is why its increase in water and proppant are so important. Since more shale is fractured, it takes more water and proppant to fill those fracs. The table above provides answers to several questions. By breaking down the data into feet, we can see the affect on production. EOG now uses a little less than twice the water of the other operators. It uses more than twice the proppant. This produces more than twice the oil of other operators and approximately a third more than its own wells in 2011 and 2012.
Before EOG made changes to its completion design, it was still out producing the competition. Comparing 2011 and 2012 wells by Statoil (STO), we see it uses shorter stages, more water and slightly less proppant per foot. STO is considered one of the best operators in the Bakken since it purchased Brigham. Given the well design, we should see more production from STO. In turn, we see much better production from EOG. STO's wide open choke could be some of the reason as well pressure decreases more rapidly, creating a need for artificial lift earlier. I would find it hard to believe we would see this large a disparity in production, especially in just six months. There is a better chance that fractures closer to the well bore not only result in better stimulation, but a less restrictive environment for the water and sand. Since STO's fractures are probably longer, the water and proppant have further to travel. I would guess this is less effective in propping the fractures open deeper into the source rock. We can safely say that EOG is ahead of the pack when it comes to well design in western Williams. This means nothing if the well is not economic. Below I have created a table of assorted wells above trying to show estimated pay back times.
|Well||Co.||Total Oil Bbls.||Oil Revenues||Total Gas Mcf||Gas Revenues||Days||Total Revenues|
The above table is an overview of revenues produced by wells in western Williams County. The data is not completely accurate as about half of the natural gas revenues I figured are NGLs, so the gas and total revenues are higher than the table reports. I calculated using a Bakken crude price of $90/Bbl and natural gas at $4. I would guess this is closer to $8/Mcf when NGLs are figured. EOG's well costs average $5.5 million. This well was probably higher, but payback is probably around 6 months. The worst well on this list was by OAS, but its well costs in this area are around $7 million. Its well will payback in two years. It is currently producing a little over 2000 Bbls. of oil per month, and will eclipse the well's cost in another 5 months.
In summary, western Williams County doesn't produce the media driven EURs of southwest Mountrail and northeast McKenzie. It does have a lower well cost, which offsets lower EURs. This area has lower well pressures than prime Bakken acreage. Well design continues to improve and EOG is leading the way. Going forward, we should see other operators testing their own completion improvements. Most importantly, if EOG can get these types of results, so can other operators.
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.