There are a significant number of theories as to why U.S. oil production has only decreased slightly. Crude prices have plummeted, and some had predicted the demise of the unconventional oil industry. This was an aggressive claim, but in reality should have seen a broader decline. Last year, the industry had estimated a large increase in 2015 production. Some have cut production, but this only maintained year-over-year levels. Operators are forced to maintain production. Lower price realizations are pushing production, as operators struggle to make debt payments. This is part of the reason U.S. oil production has ranged between 9.4 and 9.6 million bbls/day. Last week's decrease may be the beginning of a rollover. It is difficult to know if this is a one-time event or the start of further declines. Operator defaults are the key. The biggest hits to production might be bankruptcy-related.
U.S. oil inventories remain high. Light crude production is the culprit, as refiners have difficulty in cracking all the barrels. Refinery throughput is up substantially, but it can only process certain volumes of these grades. Heavy sour is imported in large quantities. This leads to the misconception we are importing too much crude. U.S. refineries use as much light and sweet blends as they can. Switching refineries to handle just U.S. grades would be an expensive and time consuming process. One that may not benefit the industry. Refined product margins have been good. This continues to motivate the cracking of crude.
U.S. and OPEC production remains high. This is the concern going forward. It is the reason for the slide in the U.S. Oil ETF (NYSEARCA:USO). World production now exceeds demand by 3 million bbls/d, and this may not change anytime soon. Even if U.S. production rolls over, like peak oil believes, it won't be enough to offset production increases elsewhere. We don't believe that OPEC will curb production. The Saudis say they may cut production after the summer, but the planned cut is minimal.
There are reasons why production may remain strong. The first is market share. Saudi Arabia and other countries want to keep and add customers. Selling more barrels will help to offset the lower price of Brent. The second is keeping revenues out of the hands of the Iranians. The current problems in the Middle East have put the Saudis at odds with the Iranians. Every Iranian barrel kept off of the market equates to fewer dollars spent in regional conflicts. The most important aspect of increasing OPEC production is refined product. The US is essentially a closed crude market, but gasoline and other products are exported. U.S. producers, in most cases, must use US refineries. This is one of the reasons U.S. exports of crude have not occurred. This refining industry benefits from the Brent/WTI differential. It will lobby to keep the ban in place.
OPEC states it is not targeting the U.S. to decrease oil production. It states Saudi Arabia supports natural market stabilization. The issue may be refined product competition. The U.S. may not export crude, but is a huge player in refined product. Many of the OPEC nations, including Saudi Arabia have increased refining capacity. The Brent/WTI differential provides an advantage to U.S. refiners. If OPEC is able to push out U.S. crude production, refined product sales could decline. Middle Eastern oil producers may be as concerned with refined products as crude. It would take a substantial decrease in U.S. production to decrease refined product sales. A decrease in U.S. production below refining capacity may decrease exports, or increase imports of Brent without a differential advantage. It's impossible to know if production will decline in the short term. It's possible most upcoming production decreases will be seen in projects with higher upfront costs like deep sea and oil sands.
U.S. production has maintained due to better economics. Horizontal wells have seen decreased costs and increased production. Better efficiencies and decreased oil service costs are the main reasons. Operators have begun utilizing better technologies that stimulate the source rock better. This process was pioneered by EOG Resources (NYSE:EOG). It fracs the rock better near the well bore. More proppant and fluids are needed to fill the void.
Currently, we are seeing more proppant, fluids and stages. Some believe production rates are decreasing. Our production numbers back operational improvements. Operators continue to improve production year after year, with wells drilled on the same or near sections. Production improves when adding to wells already on a pad. This should decrease production due to shared resource in adjacent wells. High grading is important. Poor wells are replaced with core completions. Drilling rigs have moved to the core in all major plays. Rigs have been removed completely in some instances. Exploratory basins have been hit the hardest, like the Tuscaloosa. Current oil prices will pressure all U.S. producers. The best core acreage can be economic, with most forced to complete locations here. Results improve 200% to 500% through high grading. This depends mostly on an operator's acreage.
An operator might move rigs to southwest Mountrail County, and not develop its leasehold in western McKenzie. It is choosing to drill large pads in the best areas, and not get acreage held by production in marginal acreage. The well data provided will provide some reasons why. All of the wells included have at least one year (360 days) of production. At least 90 days of production are needed to evaluate a well. One year is more appropriate, as much of the high initial pressures within the well have leveled off. Since data is needed, we are not providing current production statistics.
Expectations are that wells completed today are even better. Longer production time frames help to evaluate well design and provide more consistent data. Karst 21-17-1H was drilled by Whiting (NYSE:WLL). It is located one mile from the North Dakota/Montana border. It is 11 miles south of the Williams County border. Karst is a few miles southeast of Fairview, Montana. This McKenzie County well is located on marginal acreage. The middle Bakken is 10,600 feet deep and well costs are high. It is a 9,400 foot, 30 stage lateral. Whiting used 53,000 bbls of fluids and 3.8 million lbs of proppant. This is a fairly standard design, but Whiting used no ceramics only sand. This is probably to keep costs down.
The above map provides significant data about the Bakken/Three Forks play. Karst was completed in the southwest portion of the circle.
Production from this area has been disappointing. It would take significantly higher oil prices for it to be economic. Some operators have been forced to drill and complete here. It is motivated to get acreage held by production.
|Date||Oil (BBL)||Gas (MCF)||BOE|
This well has produced 49,660 bbls of crude. Over the first 360 days, it produced 48,592 bbls of oil. It has a low decline rate. Lower well pressures produce less resource, so there is a slower decline. This is a misunderstood concept. While some focus on high rates of decline, total production is all that matters. Operators care less about an increased decline rate, especially if the well reaches payback sooner.
Martell 36-25HTF2 is 11 miles east of Fairview, Montana. It is a test of the 2nd bench of the Three Forks. This slickwater frac was 8,500 feet long and used 36 stages. Oasis (NYSE:OAS) used 3.7 million pounds of proppant and 223,000 bbls of fluids. 100% of the proppant was ceramic.
It has produced 39,210 bbls of crude to date. It produced 37,321 bbls in 360 days. It underproduced the middle Bakken well just a few miles away. The second bench of the Three Forks has underperformed. Although it is relatively thick in this area, it requires a fairly high oil price for favorable economics.
Ty Webb 3-1-12H is a middle Bakken well drilled by Emerald (NYSEMKT:EOX). It is a 9,300 foot, 34 stage frac. This slickwater frac used 224,000 bbls of fluids and 3.7 million lbs of proppant. Ty Webb is approximately 13 miles south of Charbonneau, ND.
Over the first 360 days, it produced 50,594 bbls of oil. Wells of this magnitude are barely economic at $100/bbl oil. This does create issues for these areas, as development will be postponed. Leaseholds held by production will continue to pump, but time will be an issue. When high grading, an operator will move development to core areas and out of those illustrated above. Well costs vary. Shale depth and other variables can/may improve production and effect costs. Higher costs with high-intensity fracs are possible, as more fluids and proppant are used. This additional cost would vary by operator.
These costs have slowed the application of mega-fracs, as operators are pressured to keep costs down. Additional costs are usually offset by increased production. To show the difference in production from marginal areas to core, I have provided data from very good Bakken acreage. Keep in mind, these are some of the best wells. This does cover a fairly broad area, so there is still a significant inventory to drill. When these areas are drilled out things get interesting as economics will change. The best areas are around the Nesson Anticline, and although results do not mirror, the best leaseholds seem to be in southwest Mountrail and northeast McKenzie County.
Parshall field may be the best in Mountrail. Grail is the top in McKenzie. There are several sweet spots outside these fields that produce fantastic numbers. The core wells in this article are not the best in each field, but produce average numbers when compared to other locations nearby. Wayzetta 36-1920H is in Parshall Field, a few miles northeast of New Town. It is operated by EOG Resources. This well is located in one of the better parts, but has not been the best well. It is an 8,000 foot, 40 stage frac. Wayzetta used 17.3 million lbs of sand and 243,000 bbls of fluids. It is a middle Bakken well. This well was turned to sales in late 2013.
Its total production is 363,000 Bo to date. It produced 352,024 Bo over the first 360 days. This is important, as this well produced more than seven times as much oil as the best marginal wells listed. This is the power of high grading, or the conversion of exploratory to developmental oil programs. Using this data, an operator would only need to drill one well for every seven in marginal areas. The difference in geology is significant. It provides the needed economics for today's oil price.
Bert 1-2-11BH is a QEP Resources (NYSE:QEP) well targeting the middle Bakken. It is a 10,000 foot lateral utilizing 35 stages. QEP used 73,000 bbls of fluids and 3.4 million lbs of proppant. The above map shows how busy this field is. There are a significant number of pads already producing to the west of Bert 1-2-11BH. It is located a few miles to the northwest of Mandaree in northeast McKenzie County.
Bert has total production of 185,000 bbls of crude. Over the first 360 days, it produced 149,011 bbls. We still see a significant improvement in one year production. In this case, it produced three times the best marginal well on the list. Skaar Federal 41-3TFH is a Whiting well located in Twin Valley Field. This well is northeast of Watford City, ND.
This area has a significant amount of natural fracturing, so all the wells have been outperformers. It is considered a sweet spot. This is a 10,000 foot, 29 stage frac. Whiting used 3.1 million lbs of proppant and 52,000 bbls of frac fluids. Approximately 850,000 lbs were ceramic.
Skaar Federal has produced 218,000 bbls of crude. Over the first 360 days, it produced 277,591 bbls. Patterson Federal 2-13H is a Continental Resources' (NYSE:CLR) well. It is located in Camp Field. We used this well as an example because it is further from the Nesson Anticline and on the fringe of the core. Areas in and around Camp Field are also part of the high grading process. Patterson is northwest of Watford City, just south of the Missouri River.
It is a 9,600-foot, 30 stage frac. This well used 8.9 million lbs of proppant and 120,000 bbls of fluids. This is one of the first high-intensity frac jobs used by Continental. The result was very good. Patterson has produced 172,570 bbls of crude. Over the first 360 days, it produced 164,319 bbls.
The above map shows where current drilling rigs are located in ND. When oil was at $100/bbl, there were many scattered through marginal counties like Stark, Billings, Divide and Burke. Now there are just two rigs in Divide, one in Billings and one in Stark. No rigs are located in north Williams, north Mountrail, southwest McKenzie, and southern Dunn. The focus is around the Nesson Anticline and will continue to be until oil prices recover. This does not tell us where completions work is occurring, as many operators have a significant fracklog.
Fracklog is an inventory of drilled wells that are waiting to be completed and turned to sales. We see how rigs have consolidated into a central location. The reason is simple, fewer completions leading to increased production. This article does address high grading but not the effect of today's mega-frac completions on production. All completions used were around roughly the same time frame from 10/13 to 6/14. This provides a somewhat up to date well design and enough production data to analyze the results.
There are several other ETFs that focus on U.S. and world crude prices:
- iPath S&P Crude Oil Total Return Index ETN (NYSEARCA:OIL)
- ProShares Ultra Bloomberg Crude Oil ETF (NYSEARCA:UCO)
- VelocityShares 3x Long Crude Oil ETN (NYSEARCA:UWTI)
- ProShares UltraShort Bloomberg Crude Oil ETF (NYSEARCA:SCO)
- U.S. Brent Oil ETF (NYSEARCA:BNO)
- PowerShares DB Oil ETF (NYSE:DBO)
- VelocityShares 3x Inverse Crude Oil ETN (OTC:DWTI)
- PowerShares DB Crude Oil Double Short ETN (NYSEARCA:DTO)
- U.S. 12 Month Oil ETF (NYSEARCA:USL)
- U.S. Short Oil ETF (NYSEARCA:DNO)
- PowerShares DB Crude Oil Long ETN (NYSEARCA:OLO)
- PowerShares DB Crude Oil Short ETN (NYSEARCA:SZO)
- iPath Pure Beta Crude Oil ETN (NYSEARCA:OLEM)
In summary, high grading has had a major effect on U.S. production. It is much of the reason lower rig numbers and reduced completions have not decreased production. Completions have been centered on core acreage in the Bakken, Niobrara, Eagle Ford, Permian, etc. Core wells produce significantly more crude in the first year of production than marginal areas. The best current Bakken wells can produce 300,000 to 400,000 bbls of crude (excluding natural gas and NGLs). Lower pressured areas can produce 40,000 to 80,000 bbls in ND. All major U.S. plays have significant differences in production. The increases from high grading can be 3 to 7 times better than marginal leaseholds. This means an operator can maintain production drilling and completing just one core well as opposed to several marginal locations.
Disclosure: I am/we are long UWTI, EOG.
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