We continue to see well design create significant production improvements. These improvements should increase costs, but this isn't being realized. Well service costs are heading lower, plus drilling and completions work is being done in a shorter period of time. Longer laterals, an increased number of stages, increased proppant and larger volumes of water are still translating to lower costs.
EOG Resources (NYSE:EOG) can be thanked for the push in better well design. It is the best unconventional operator in the world, and owns a large number of the best-producing wells in the United States. Its secret is source rock stimulation. EOG focuses on breaking up rock. By creating more fractures, it releases the most resource.
While most operators like Continental (NYSE:CLR), Whiting (NYSE:WLL) and Exxon (NYSE:XOM) were still using sliding sleeves and ceramic proppant, EOG was doing something different. It was using plug and perf with very large amounts of sand. The company focused on fracking around the well bore. This produced a large number of wide, short fractures. This void needs large amounts of sand to keep the fracs open. It has produced monster results, and most operators are now trying to duplicate this design.
EOG's sand-heavy frac works in all the major plays. It has seen fantastic results in the Bakken, Eagle Ford, Permian, Niobrara and other areas. This, coupled with high grading, is the reason oil production in the United States has maintained a lower completion count. This production has helped to keep realized WTI prices and the U.S. Oil ETF (NYSEARCA:USO) at the current lower levels. New technologies and better-trained employees decrease the time needed to complete tasks. We all know that time is money, and probably the easiest way to decrease costs. Currently, oil E&Ps have the advantage, and oil service companies could have significant issues. Service costs are already down 10-15% this year, and we could see another 10-15% before year-end.
Two years ago, well designs were less complex. Lower oil prices have motivated operators to improve production. This has not only lowered costs, but improved payback times. Economics of $90/bbl oil two years ago are much closer to $60/bbl now. Older well designs utilized the same lateral length, but used 30 stages. It also used sliding sleeves and ceramic proppant. We saw 3-4 million pounds of proppant and 50000 bbls of water in an average completion.
The diagram above shows why plug and perf/cemented liner applications have worked well. Sliding sleeves only had one frac port/stage. All of the force to break up the rock was focused on one point every 333.33 feet. The force created was too focused and created fractures deep into the shale. Initially, this was thought to produce more resource, but EOG found something different.
In the case of Whiting's completion design change, the move to 40 stages created lengths of 250 feet. This decreased space in each stage by 83.33 feet, which allows the operator to increase the hydraulic horsepower of the pump trucks. It then was able to increase the number of access points to the shale and spread it out over three perf clusters. This not only shortens the fracs, but creates a better breaking up of the shale close to the well bore. Since the completions crew is able to break up more rock, more resource is released.
In response, more sand and water are pushed downhole to fill in voids and prop it open. Sand is much cheaper than ceramics, and offsets the cost of higher volumes/ft. Frac jobs now consist of 10 million pounds of sand and 100,000 bbls of fluids. These numbers continue to increase, as does production.
We could highlight a number of operators throughout the U.S. to show better completion methods. In this case, we are looking at QEP Resources (NYSE:QEP). The company's best acreage is located in North Dakota's Grail Field. It acquired this leasehold from Helis in August 2012 for $1.38 billion. Grail Field is one of the best areas in the Bakken, with EURs in excess of 1,000 MBoe in the middle Bakken and upper Three Forks.
Source: QEP Resources May Presentation
QEP's well design has morphed from 30 stages and 3 million lbs of proppant to 50-plus stages and 10 million lbs of sand. Its original completion design was a standard in late 2013. Given the change in volumes of sand, source rock stimulation is opening up the shale over 300% better. This is where the industry is going, at least in core areas. QEP estimates an uplift of almost 50% from original completions and 22% better than the mid-sized at 120 days of production. To test QEP's estimates, we will look at its Moberg well results.
Although there are 15 Moberg wells, we are focusing on two specific pad sites. The map above provides these locations, which are the northernmost and southernmost pads.
The WellDatabase report shows the wells we are highlighting with associated production. The first well began producing in October 2011, while the last six were all completed in the middle of 2014.
The production data shows how the first well produced until a second well was added in February 2013. We then see an influx of resource in July and August of last year as two three-well pads were added. Starting in April 2014, we see no production for three months. This was due to the shutting in of the two existing wells while the pads were completed. This is very important with respect to depletion. Depletion estimates are skewed. Oil bears will produce depletion data that is higher in current wells, as they do not provide for the times wells are shut in. Wells are sometimes shut down for service or re-fracs, but usually it is due to adjacent wells turned to production.
Moberg 4-20/21H was the first producer of the group. Its first month of well life was October 2011.
|Date||Oil (BBL)||Gas (MCF)||BOE||Water|
This was a fantastic well. This completion did not have good well design data, as it was completed before North Dakota required more descriptive documents. Looking at the old Helis well design, expectations would be for 28-stage frac, 80,000 bbls of water and 3 million lbs of ceramic proppant. It has produced 336,000 bbls of oil over approximately 34 producing months. It is important to note the surge in production in September 2014. After the adjacent wells are completed on the later pad, the communication produces a pop in production. Although this is an older well, the depletion rate was relatively low. This is especially true when compared to other wells completed in 2011. Production didn't peak until five calendar months after well life started. This well is over three years old and still producing over 4,000 bbls per month.
The second well completed in this eight-well grouping was Moberg 13-17/16H. This Three Forks well is a 30-stage frac using 46,000 bbls of water and 3 million pounds of proppant.
It has produced 292,000 bbls of oil. It also saw a surge in production after the adjacent pad was completed. Although this well steals some resource from the other locations, it was still a very good producer over the first 19 producing months. More importantly, it is still producing +15,000 bbls/month. If it wasn't for the increased production due to the recent well pad, we could estimate production closer to 8,000 or 9,000 bbls/mo. And all of this with a remedial-type well design.
The above map is the northernmost pad and the location of Moberg 13-17/16H. Moberg 2-17-16TH started producing in July 2014. It is an upper Three Forks well.
It has produced 164,000 bbls of oil in just seven months. This 32-stage completion used 107,000 bbls of water and 8.3 million pounds of proppant. This is an excellent well producing in the range of 20,000-30,000 bbls/mo. The recent drop to a little under 16000 bbls/mo was strange, but the well may have had fewer producing days.
Moberg 3-17-16BH has produced 91,000 bbls of oil in seven months. This well is a middle Bakken underperformer.
This is a 32-stage frac using 107000 bbls of water and 8.3 million pounds of proppant. The final well in this pad (and the well furthest south) is Moberg 4-17-16BH. Its middle Bakken production data is below. This well did not produce as well as the others, but it is an interior well. This means it has a well on each side, which would steal more resource than the outside wells. Communication can be an issue with pad drilling. It is impossible to know how close wells can be spaced, and the fracs can inhabit the same area from separate wells. This means some resource will be shared, lowering EURs.
Total production is 151,000 bbls of oil. The well design includes 32 stages and 110,000 bbls of water. 8.4 million pounds of sand is part of this design. It is another very good result. After production peaked in October, the well has maintained production for three months.
In the southern pad, Moberg 17-16-20-21LL has produced 164,000 bbls of oil. In general, these wells have produced better than the northern pad. It is an upper Three Forks well.
This is a 32-stage frac. This completion design used 110,000 bbls of water and 8.4 million pounds of sand. The first three months of production produced over 100,000 bbls of oil. Revenues over the first 90 days were almost $7 million. This includes both oil at $60/bbl and natural gas at $4/Mcf.
Moberg 2-20-21BH has produced 98,000 bbls of oil and is a middle Bakken well.
Moberg 2-20-21BH is a 33-stage frac using 113,000 bbls of water and 8.7 million pounds of proppant. The last well in the southern pad is the farthest to the southeast. Moberg 1-20-21BH has produced 165,000 bbls of oil. This well also underperformed. It is also located as an interior well next to a current producer. This does provide data as to how much well communication decreases well production. The data is skewed, because the original well has been producing for some time. More resource has been produced from that location, which provides less to be pulled by wells added later.
Moberg 1-20-21BH produced more than 40,000 bbls of oil per month for the first two months. It has produced 165,000 bbls of oil. This is the best well of the group.
This middle Bakken well is a 32-stage frac with 110,000 bbls of water and 8.2 million pounds of sand. This frac job and the other five more recent wells all fall into QEP's mid-sized completions. QEP estimates have these wells producing 122 MBoe over the first 120 days. Below is a chart of the combined production of all six wells. I have divided this into two charts, one for each three-well pad. From this, we will see how its mid-sized completions are doing with respect to company estimates. Northern pad data is below.
Not all of the wells have full production data in July, so we will use August as the starting date. These wells produced a total of 284,302 barrels of oil and 292,210 Mcf. This equates to 337,581 Boe. Each well averaged production of 112,527 Boe. This is roughly 10,000 Boe less than QEP estimates for mid-sized completions.
Data from the southern pad is just as good. Gas volumes were low in the first month. Most pads are not able to sell immediately, as the pipelines aren't in.
This pad produced 321,757 barrels of oil and 207,343 Mcf of natural gas in the first 120 days. This equates to 359,562 Boe. On a per-well basis, each well produced 119,854 Boe. This is just below the company estimate of 122,000 Boe.
As a comparison, I have included the first eight months of production for Moberg 4-20/21H. Due to production issues in the first two months, I am beginning the production analysis starting at month three.
It produced 119,008 barrels of oil and 135,630 Mcf. This equates to 143,738 Boe.
The second well is Moberg 13-17/16H. Below is its first six months of production.
It produced 126,114 barrels of oil and 134,180 Mcf. Total production is 150,579 Boe. These results prove that the first wells were outperformers. This isn't correct, as it was drilled as single wells and the first locations on-site. There is a very large difference in wells that produce with adjacent locations on both sides of the horizontal. If we remove those wells from the data, we find production is up significantly. The data below correlates with these two wells from the southern pad.
The outer wells from the southern pad produced 328,250 barrels of oil and 305,358 Mcf. This equates to 383,962 Boe. Over the first six months, the average production per well is 191,963 Boe. The same was done for the northern pad.
As with the other data, the first month was excluded from the results. The outer wells of the northern pad produced 296,437 barrels of oil and 351,968 Mcf. This equates to 360,612 Boe. These locations averaged 180,306 Boe over the first six months of production. If we use the average of the first two wells drilled versus the four outer wells from those same areas, we see a 21% uplift in production.
Looking at the well economics of South Antelope, we see some very good results. Using $60/bbl, oil revenues are $9,370,320 in the first six months. With $3/Mcf natural gas, an additional $492,995 is added. Six-month revenues for the four outside wells were $9,863,315. Mid-sized fracs are currently costing QEP just $7.5-8 million (new 50-stage fracs are $9 million in South Antelope). Payback times are exceptional.
We do not currently have any real good data on QEP's most recent 50-stage fracs. It is important to note that these wells provide an estimated 25% uplift over the mid-sized completions. When using three-well pad averages (with an already existing well), the numbers came in under company estimates. Much of this has to do with wells already producing. One location of each three-well pad produced 42% less than the other four wells. In both occasions, these wells were located between a well already producing and a new location. The wells producing on the ends of the pad produced well above the current QEP type curve. We estimate that standalone wells would be much better than any of these results, and again better than the best locations of these pads.
In summary, many discount the production uplift from newer sand-heavy fracs. Operators are able to high-grade with better well designs and continue to produce at current levels with just a small number of completions when compared to just a year ago. We have not fully realized the increase in production, as many operators are still working on the design. We expect most of the operators to move to 50-stage fracs this year. When comfortable with this design, most will be using this exclusively.
We have covered and been following the evolution of EOG's laterals, and the results are impressive. The problem is that most operators are behind the curve, so it will take time. It is interesting that the U.S. can continue to produce more oil, with many operators still using designs that are not optimal. Without access to confidential well results, it is difficult to gauge the upside to current well technology. This is the reason for the continued issues concerning predicting U.S. production.
Over the last two weeks, we have seen production spikes from the EIA Crude Inventory Report, and it is possible this will continue if U.S. producers see better returns. Going forward, we would expect fewer completions to provide more resource per well. This means operators will have to do less to produce higher revenues. They can also operate at much lower oil prices. This may be a cause for concern in the coming months. OPEC continues to add production. Saudi Arabia and Iraq are motivated to secure customers before additional Iranian barrels hit the market. Upcoming refinery maintenance will decrease throughput without a rollover in production. If this is the case and dollar strength continues, things could get interesting in the latter part of the year.
Disclosure: The author is long EOG, WLL. The author wrote this article themselves, and it expresses their own opinions. The author is not receiving compensation for it (other than from Seeking Alpha). The author has no business relationship with any company whose stock is mentioned in this article.
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