North Dakota On Track For New Crude Oil Production Record In 2018 -- Zacks -- January 28, 2018

From Zacks.

As per North Dakota’s oil regulator, the state’s daily crude output rose 0.9% in November after climbing 6.9% in the previous month.

Reflecting a healthy increase, the newest numbers confirm the resurgence in volumes extracted from North Dakota, centered on the Bakken Shale formation. As daily output consolidated above 1 million barrels for the tenth month in a row, the state’s total number of producing wells numbered 14,324 at the end of November, a new all-time high.

Interestingly, natural gas output was up 1.4% in November to 2,095,342 thousand cubic feet per day – another record – as operators scrambled to the core areas of the Bakken where wells tend to produce more gas along with crude.

Some 54 drilling rigs were active in the state in November. The all-time low of 27 was set in May 2016, while a year ago, North Dakota had just 37 rigs operating. A closely watched yardstick of North Dakota oil industry's strength, the year-over-year improvement in the number of units searching for oil and gas in the region indicates essentially steady drilling activities and production. However, the rig count is still down considerably from the peak of May 2012 when North Dakota had 218 units drilling.

More rigs in operation and stable production not only confirms the positive developments for the state of North Dakota, but also points to the rising flood of U.S. shale-driven production.

Now at a financial equilibrium, the shale firms are putting more rigs and employees back to work. Throughout the downturn, producers (in North Dakota and particularly the Permian Basin in Texas) worked tirelessly to cut costs down to a bare minimum and look for innovative ways to churn out more oil from rock. And they managed to do just that by improving drilling techniques.

Friday, April 8, 2016

India, the new "China." From Bloomberg/Reuters:

The world’s second-most populous nation is increasingly becoming the center for oil demand growth as its economy expands by luring the type of manufacturing that China is trying to shun. And just like China a decade ago, India is trying to hedge its future energy needs by investing in new production at home and abroad. 

India may have one advantage its neighbor to the northeast didn’t. While China’s binge came during a commodity super-cycle that saw WTI crude reach a high of $147.27 a barrel in 2008 -- due in no small part to its demand -- India’s spurt comes during the biggest energy price crash in a generation.

While oil has tumbled more than 50 percent from mid-2014 levels, the South Asian nation spent $60 billion less on crude imports in 2015 than the previous year even while buying 4 percent more.

In 1999, China’s economy was less than a 10th of its current size of more than $10 trillion, and bicycles vied for space with taxis and buses on crowded streets in major cities like Shanghai. In the ensuing 17 years the economy, spurred on by foreign investment in manufacturing, grew from the seventh largest in the world to No. 2. Vehicle sales surged and oil demand has nearly tripled since then, positioning the country to overtake the U.S. as the world’s largest crude importer this year.

Active rigs:

	4/8/2016	04/08/2015	04/08/2014	04/08/2013	04/08/2012
Active Rigs	31	91	191	185	208

RBN Energy: Natgas Storage Spreads Are Back, Alright!

A few years ago, natural gas storage was one of the hottest segments of midstream infrastructure development.   But along came shale, then oversupply, then depressed prices.  The forward curve flattened out, killing off new storage development projects and putting a lot of financial pressure on those companies that own or lease storage capacity.  But recently things have shifted, at least part of the way back to the good ole days.

The summer/winter spread currently sits at $0.63/MMBtu (April 7, 2016), the highest level since 2012, and up significantly from the past years average of around $0.30/MMBtu.  Midstream companies with available storage should be able to lock in higher prices compared to past years.  In today’s blog, we look at the situation now facing natural gas storage operators and show how recent shifts in the market may affect their returns.

USGS: fracking does not cause earthquakes. For the archives. We already knew this.

A study by the U.S. Geological Survey identifying the potential for natural and human-induced earthquakes identifies wastewater injection—not fracking—as the primary cause of increased tremors in the south central U.S.

In a first-of-its-kind study, USGS examined the potential for human-induced and natural earthquakes for a one-year period to supplement its standard 50-year forecast. Within the central and eastern U.S. (CEUS)—an area populated by 7 million people—the agency’s report said there’s a chance of damage from all types of earthquakes similar to the natural earthquakes in the high-hazard areas of California.

The maps released with the study show that east of the Rocky Mountains, much of the seismic activity is in Oklahoma, Kansas and Texas. Although this activity is sometimes attributed to hydraulic fracturing conducted by the oil and gas industry, USGS said “this process is only rarely the cause of felt earthquakes.”

According to the report, “Wastewater disposal is thought to be the primary reason for the recent increase in earthquakes in the CEUS.”

Bakken average production costs lowest among shale plays: again, for the archives; previously posted from a different source; this from Bakken Magazine:

Oil and gas industry upstream costs in 2015 were 25 percent to 30 percent below 2012 levels in the Bakken and four other onshore areas evaluated.

To better understand the costs of upstream drilling and production activity, EIA commissioned IHS to study costs on a per-well basis in the Bakken, Eagle Ford, Marcellus and Permian (Delaware and Midland basins) plays. Titled “Trends in U.S. oil and natural gas upstream costs,” the report is available here.

The period studied is from 2006 through 2015, with forecasts to 2018. Well costs in the regions studied were:

- Bakken wells costs were $7.1 million in 2014, but will drop to $ 5.9 million in 2015.
- Eagle Ford wells averaged $7.6 million in 2014, but will fall to $ 6.5 million in 2015.
- Marcellus wells will cost $6.1 million in 2015 after having an average cost of $6.6 million in 2014.
- Midland Basin wells were $7.7 million in 2014, but will drop to $ 7.2 million in 2015.
- Delaware Basin wells cost $6.6 million in 2014 and will drop to $5.2 million during 2015.

Yips. for my brother-in-law, from ESPN, the video will go viral --

Ernie Els made dubious Masters history in the opening round Thursday by scoring a 9 on the par-4 first hole -- the highest in 80 years of the tournament.

Els, 46, a World Golf Hall of Famer who has won four major championships, six-putted the first green at Augusta National after chipping from off the green to within 3 feet for what appeared to be an easy par.

It could have been worse. The Masters live scoring had it listed as a 10 all day, until officials conferred, reviewed videotape and determined that Els had taken just six putts, instead of seven. He finished with an 8-over-par 80 and is tied for 81st.

Comparing Well Cost Across Various US Basins -- April 1, 2016

This was a data point from this week's update on the Permian:

EOG estimates well costs at $11.5 million/well; hopes to get costs down to $6.8 million/well this year (compare with Bakken which is clearly in the $7 million/well range).

That well cost comparison goes along nicely with this EIA analysis (a huge "thank you" to a reader for spotting this):

The "blue" and the "black" might be a bit hard to read. I believe "blue" is the Eagle Ford and "black" is the Permian (Delaware).

I am only interested in comparing "oil" basins, not "gas" basins. Therefore, throw out the Marcellus (green) line.

When the Marcellus, a "gas" play is thrown out, the Bakken is the second lowest; beat only by the Permian (Delaware). But for cost, the Bakken clearly beats the Permian (Midland) and the Eagle Ford, and not by a trivial amount. It's too bad the Bakken is so dependent on costly CBR.

Idle Chatter On Costs Of Completed Wells In The Bakken -- September 20, 2014

About a week or so ago, a reader sent me an e-mail regarding the high cost of a CLR well in the Bakken. I replied at the time:

It probably was an expensive well. The operators all say they are bringing prices of completed wells down, to the neighborhood of $7 - $8 million but I don't put much faith in those estimates. The biggest problem is figuring out what is being paid for; too many things that can be hidden in numbers like that. I think we will continue to  see "cost containment" in the corporate presentations, but with a) huge proppant volume; and, b) slickwater adding 35% to the average EUR in the Basin, I think the emphasis is going to be on raising EURs this year and next (despite the cost) and then get back to trying to contain costs. Operators will see savings in pad drilling and leasing costs, offsetting completing/fracking costs.

I wrote that on September 18, 2014. Tonight, while reviewing the most recent CLR presentation, my thoughts were confirmed. Slide #50 of the presentation shows the cost of completed CLR wells. Between 2012 and early 2014, operators were talking about decreasing the cost of completed wells. CLR was reporting the following:

• 2012: $9.2 million
• 2013: $8.0 million
• 1H14: $7.8 million
• But then, starting earlier this year, the price of completed CLR wells increased from $7.8 million to $10 million, due to higher proppant volumes and slickwater. 

It looks like we're back to $10 million wells. Remember, these are long laterals. I believe wells were costing in the neighborhood of $4 - $6 million for short laterals when the boom first began in the Bakken. In other words, the costs of completed wells is still in the same ballpark as when the boom began, but the wells are much, much better, and the time from spud to first production has decreased significantly.

Whiting has differentiated itself in the Bakken as the "low cost operator' in its corporate presentations. It will be interesting to see if that continues to be a bullet in their presentations once they acquire KOG, with their very expensive wells.

Costs Of Drilling In The Bakken -- Motley Fool

I don't think there's a lot new in this Motley Fool article for regular readers of the blog, but it's a nice summary of what Bakken operators are spending to complete a well in the Bakken:

Similarly, Newfield Exploration said that it's currently drilling and completing wells in the range of about $8 million-$8.5 million, even recently completing a best-in-class well for $7.4 million. That's a massive improvement over the company's average first-quarter gross completed well cost, which came in at $9.8 million. 

Most of the other Bakken operators are also mentioned, including KOG:

And last but not least is Kodiak Oil & Gas, a company whose operations are almost exclusively focused in the Williston Basin. Though Kodiak pays more per well than the aforementioned firms since its wells tend to be much deeper, it too managed to bring well costs down to the $9.7 million-$10.2 million range, a roughly 15%-20% reduction from year-ago levels.

The Bakken Just Keeps Looking Better Every Day

Just the other day it was noted that the cost for Bakken wells, at least for Hess, is dropping significantly, and quickly.

Not so for the off-shore folks. Wouldn't this just ruin your day if you were the CEO of BP and were told this wonderful news? The Angola  project came in at $4 billion over budget.

A massive BP PLC oil development off the coast of Angola has come in $4 billion over budget after being delayed by a year, The Daily Telegraph reported Monday, citing an executive. 

The project, more than 100 miles offshore, was originally slated to start producing oil in late 2011 and to cost about $10 billion, the newspaper said. Instead, it began production in December, 2012 (over a year late). 

While analysts thought the project would cost nearer $12 billion, the total is now expected to be "up over $14 billion" once all the wells have been drilled and connected, Gerry McGurk, BP Angola's vice president, disclosed, according to the newspaper. 

Actually, the reality is a bit worse than the headline. The headline: $4 billion over budget. The reality "up over $4 billion more" than projected by the company. "Up over" leaves a lot of room for further upside adjustments.

And if it were a $1,000 billion project, the $4 billion would be a rounding error. But $4 billion is 40 percent -- repeat -- 40 percent -- of the company's anticipated cost. Meanwhile, at the first link above, the cost for a Hess well in the Bakken has dropped 36% over that same time period.

Bakken Well Costs

From the Hess 1Q13 earnings transcript:

Well cost for the first quarter averaged $8.6 million per well, down 36% from $13.4 million per well in the first quarter of 2012 and down from $9 million per well in the fourth quarter of 2013.

Not trivial.

***************************

Back on January 24, 2010:

This may or may not be important in the future as a trend (cost and time to drill a horizontal Bakken well), but I don't want to lose the link. If you scroll to the top of that link, Slawson reports that it has put in a horizontal well in 16 days and for less than $3 million. The rule of thumb for a horizontal well in North Dakota: 30 days (it used to be 45 days) and $4 - 6 million.

I believe wells in 2010 were generally short laterals.

I recall many discussions over the past two years that a long lateral at $10 million was about the same as a short lateral for $5 million. So, when I see the Hess 1Q13 quote of $8.6 million per well in 2013, I find it quite interesting. Mike Filloon recently said that well costs were coming down faster than folks generally realized.

Bakken Well Costs Are Decreasing Faster Than Companies Indicate -- Mike Filloon

Reporting at SeekingAlpha.

Two words: seed corn.

New Technology Saves 7 Days In Drilling Time

NDIC says it takes about 20 days to reach total depth.  It looks like about five days to reach vertical depth and fifteen days to reach  total depth from there. I don't read many well files, but of those I read, it doesn't seem like all that many wells are reaching TD in 20 days. I still use 30 days as a general rule of thumb. (The guys and gals in the field are probably laughing.)

A reader sent this story; it's very technical but worth reading even by a layman. High points:

• international conference; held in Amsterdam
• Forbes 500 oil services company: Weatherford
• Bakken used as a laboratory (again)
• new steering technology
• compared two wells

• well #2: horizontal rate with old technology: 31 feet/hour
• well #1: horizontal rate with new technology: 38 feet/hour

• well #2: length of lateral using old technology: 8,956 feet (failed to meed planned TD)
• well #1: length of lateral using new technology: 10,217 feet

• well #2: 8,956/30.67 = 292 hours of actual drilling with old technology
• well #1: 10,217/38.08 = 268 hours of actual drilling with new technology

Conclusion of the article:

As a result of the smoother wellbore, the operator had a trouble-free casing run in Well #1. The system consistently achieved more than 93% rotation in the lateral in both wells. This was a significant improvement from previous wells, which achieved roughly 70% rotation. On the first well, sliding time was reduced from 30% to 8%, saving seven days of rig time and the associated drilling costs.

As drilling progressed, these wells required frequent directional updates, due to formation faults. Consequently, this required many target changes for geosteering. ROPs in the first Bakken well were higher than the second well, since more time was spent sliding to correct the well path on #2 without TBS technology. Use of TBS technology on Well #1 enabled the operator to have precise steering control and drill a smoother wellbore. The second well reached TD early, due to an inability to overcome high frictional forces in the lateral leg.

From the linked article, this is the technology:

To improve performance in these [Bakken] laterals, operators have been looking for a while now, for an economic alternative to rotary steerable systems (RSS’s), while still retaining their basic benefits.

Lead author Wendell Bassarath said that a new system to achieve 3D directional control was developed to improve drilling efficiency, using targeted bit speed (TBS) technology. The system uses a conventional positive displacement motor with a bent housing and an MWD tool that mimics many of the features offered by an RSS. The steering technique was achieved by accurately modulating the flow of the drilling fluid through the drillstring.

This allowed rapid variations in the drilling parameters to accurately control the bit speed along the desired toolface setting. If wellbore objectives could not be achieved in rotary mode using TBS technology, then the mud motor could be oriented in a conventional manner to follow the well plan.