Monday, July 27, 2015

$200 Billion, 45 Projects, Most Deep-Sea Deferred, -- July 27, 2015

Reuters/Rigzone is reporting:
Oil and gas projects in deep basins account for most of deferred investments worth more than $200 billion made due to the oil price crash.
Oil and gas majors have slashed capital expenditure budgets between 10-15 percent this year in response to oil prices halving over the past year. A large chunk of these cost savings have been made by deferring investment decisions in expensive projects, shelving more than $200 billion worth of investments. .... dentifying 45 major project deferrals across the globe.
As much as 10.6 billion barrels of oil equivalent in resources located in deep or ultra-deep oil and gas projects are affected by the delays, showing projects in frontier areas are worst hit. Canada's oil sands projects make the country most vulnerable to project deferrals, with 5.6 billion barrels of liquid reserves at risk in the country.
Related, from Bloomberg/Rigzone:
The deep-ocean strategy is coming back to bite South Korean shipyards.
Hyundai Heavy Industries Co., Daewoo Shipbuilding & Marine Engineering Co. and Samsung Heavy Industries Co. -- South Korea’s Big Three shipbuilders -- ventured into offshore oil rigs starting around 2010.
The goal was to avoid direct competition with China, where inexpensive labor could churn out low-profit tankers at cheaper rates. With oil prices climbing toward $100 a barrel, offshore rigs seemed like a savvy bet. Today the strategy seems to have backfired.
Struggling with technology and a plunge in oil prices that has discouraged exploration.
It’s the latest example of difficulties for the global shipbuilding industry, after a glut of vessels and low freight rates have spelled financial trouble for Chinese yards in recent years, prompting them to seek government aid.
It takes 6 - 7 years to bring a deep-sea project on-line once decision is made to drill. 

Setting us up for $200 oil in 2020.

Notes From Mike Filloon's Most Recent Seeking Alpha Article On The Bakken And Mega-Fracks -- July 27, 2015

I type this stuff out to help me remember; much (most) of it is taken directly from article. There will be factual and typographical errors. Readers should read the original article; these notes are only to help me understand the Bakken. The shorthand used is for my use and may be confusing to readers.

Data points from the article:

US holds resilient at 9.5 million bopd; production is a continuing debate between bulls and bears.

Production bulls believe in high-grading and well design.
Production bears believe horizontal production will fall because higher prices are needed.

But: if there are fewer completions and decline rates are high, why hasn't production tanked? Newer well decline rates are very low and cannot be compared to historical averages.

Repeat: Newer well decline rates are very low and cannot be compared to historical averages.

Three-peat: Newer well decline rates are very low and cannot be compared to historical averages.

When oil prices fell, operators moved quickly. Exploratory programs decreased (ceased?) and rigs focused on core acreage.

Core acreage:
  • Bakken: Nesson Anticline
  • Eagle Ford: Gonzales and Karnes
  • Permian: Midland County
Operators took the rigs still under contract, drilled wells as fast as they could, but did not complete them: this left a huge "fracklog" of 4,000 to 5,000 wells. Last year the fracklog was just 400 to 800. In the Bakken alone, the fracklog rose to 925 two months in a row, April and May, 2015.

Filloon says that the US is not alone: production increases continue in Iraq, Saudi Arabia, and the UAE. My comment: on a percentage basis, the increase in Saudi Arabia is very, very small (1%) despite a 5-year, $35 billion program announced in 2012. And much of the Saudi production increase is needed for a) domestic consumption; and, b) for its new refineries, nearing 1 milliion bopd cpacity.

Filloon then lists the usual litany of global bearish factors.

Filloon says the following areas are economic at today's prices:
  • core areas in the Permian, Bakken, Eagle Ford, Powder River Basin, and the Niobrara
Filloon suggests defaults may occur. Operators with no core acreage will have issues.

Filloon then discusses well design improvements. Over the past two years:
  • 9,000-foot, 30-stage laterals
  • three million lbs proppant, 50,000 bbls of fluids
Now, huge frack jobs:
  • 50+ stages, 6+ million pounds of sand
  • 100,000 bbls of frack fluids
  • some jobs are much bigger
  • Other factors:
  • communication: adjacent wells increase production
  • sand heavy fracks are increasing production faster than expected
Get this:
well production from core areas can out-produce marginal areas up to 500%
on average, it is closer to 300% but it depends on the areas used for comparison
Filloon spends a lot of time on the issue of communication.

Filloon gives the EOG experience, which has been previously discussed.

Then CLR, the Salers Federal 3-27H well:
  • 50-stage, long lateral
  • 312,000 bbls of frack fluid
  • 18 million+ lbs of sand plus 1.2 million lbs ceramic
  • of the seven wells on the Salers Federal pad, only three are producing
  • the four that are not producing, are part of the fracklog
  • in nine months: $11 million in revenue at $60/bbl and $3/Mcf
  • 172,950 bo; 207,820 MCF
  • although the Salers Federal 3-27H produced very well, it stimulated production elsewhere
Filloon also noted that there is almost no depletion; the well produced for a whole year and is still producing almost 20,000 bbls/month of crude
  • essentially, we may be seeing re-fracking of portions of neighboring wells
Filloon even suggests there may be communication across source rock; from the middle Bakken to the Three Forks.

Filloon then talks at length about QEP, the Grail field, and the Moberg wells. It is improtant to note that the Moberg is not QEP's newest well design.

Risk: if an operator were to drill too close to another well for the purpose of frackign into a well nearby, it could ruin the reservoir. This could significantly decrease or stop production from all wells effected. The hope is to increase the estimated reserves of the well by re-opening fracks that have closed or opening new fissures.

1,123 Community Colleges Across The US; Williston State College Tetons Tied For 2nd Highest GPA -- July 27, 2015

The Williston Herald is reporting:
The Tetons women’s basketball team at Williston State College is raising the bar when it comes to sports and academics. With a collective GPA of 3.67, the team ties for second highest GPA for junior colleges across the nation.
Grilling 101

One starts with Johnsonville Beef Franks:

No comments on the outfit, please. I've got my swimming trunks on under the towel. We were swimming and then came up to grill. Sophia had been in a "grouchy" mood but she perked up when she learned she was going to be responsible for the hot dogs.

One at a time, clamp down tightly:

Only one task: "Do not drop. Do not drop. Do not drop."

Okay, there it is, done. Wow, none dropped. Okay, let's move on -- beer can chicken tomorrow.

Keeping Secrets In Alaska? -- July 27, 2015

From SeekingAlpha:
  • Prudhoe Bay field owners BP and ExxonMobil have asked Alaska regulators to approve plans to increase the volume of natural gas allowed to be produced and sold from the North Slope field
  • The Alaska Oil and Gas Conservation Commission has limited gas offtake at 2.7B cf/day of gas since 1977, but the two companies are asking to increase the rate to 4.1B cf/day to supply a planned Alaska gas pipeline and liquefied natural gas export project; a separate application for gas offtake from the Point Thomson gas field, which also would supply the LNG Project, is expected later.
  • ~8B cf/day of gas is now produced - along with oil - at Prudhoe, but most is injected back underground to maintain pressure in the reservoir to aid oil production; the concern is that if ~50% of the produced gas is shipped to markets via pipeline, there would be less gas injected and less support for pressure in the reservoir, resulting in lower oil output.
  • BP is the Prudhoe Bay field operator and a major stakeholder along with XOM
  • ConocoPhillips, also a major stakeholder, was not included in the application and says it was not aware that the other two companies would do so.
But that other data point: isn't that interesting about maintaining pressure in the reservoir; at risk of decreased oil production.

Eleven (11) New Permits -- North Dakota -- July 27, 2015

Active rigs:

Active Rigs73193207182136

Wells coming off confidential list Tuesday:
  • 24157, 1,179, Whiting Pronghorn Federal 21-15H, Park, Three Forks, 40 stages, 5.9 million lbs, t2/15; cum 42K 5/15;
  • 27674, 1,393, Hess, EN-Leo E-154-94-2423H-4, Three Forks B1, 35 stages, 2.4 million lbs, all sand, Alkali Creek, t6/15; cum --
  • 28406, 1,602, Whiting, P Wood 154-98-4E-26-15-4H, Truax, middle Bakken, 24 stages, 2.9 million lbs all sand, t2/15; cum 49K 5/15;
  • 29491, drl, XTO, Rita 44X-34C,
  • 30089, SI/NC, BR, CCU Dakotan 5-8-17TFH,
Eleven (11) new permits --
  • Operators: Statoil (5), Whiting (5), Denbury Onshore
  • Fields: Stony Creek (Williams), Twin Valley (McKenzie), Cedar Hills (Bowman)
  • Comments: Statoil and Whiting each with permits for one 5-well pad for each
One (1) producing well completed:
  • 24567, 524, Sinclair, Horovitz 10-09-1H,

It WIll Make The State Meaner, Leaner -- July 27, 2015


November 21, 2015: revenue shortfall grows

October 4, 2015: The Dickinson Press provides update on metropolitan debt in western North Dakota: 
First, the revenue, the forecasts of the gross production tax revenues drawn from oil industry and allotted to the cities through distributions from the state. Three figures: first figure is the revenue distributed by the state back to the city in surge funding (one-time funding last spring). The second figure is the forecast from the last legislative session in January, 2015. The third figure is uses oil prices from August, 2015 (all figures in million of dollars, and rounded):
  • Williston: $64; $38; $36
  • Tioga: $11; $4, $3.4
  • Stanley: $17; $3; $3
  • New Town: $9; $4; $4
  • Watford City: $32; $12; $11
  • Killdeer: $9; $4; error?
  • Dickinson: $44; $22; $20
Now, the debt going into next year:
  • Dickinson: $113 million
  • Watford City:
  • Minot: $85 - $100 million; after bond issue in November, $102 million
  • Williston: $131 million (lock box: $70 million for new recreation center to be financed through special sales tax)
Disclaimer: I've never followed very closely nor understand well the budget process in these metropolitan areas. If this information is important to you, go to the source.

Let's put the Williston debt in perspective:
  • According to Google, Harold Hamm's net worth in 2015 is: 9.4 billion
  • Williston's debt is about $130 million + the $70 million for the rec center (which I think is already paid for through the sales tax, but I could be wrong on that).
  • Regardless $200 million (Williston debt) / $9.4 billion (Harold Hamm's net worth) = 2%.
  • Harold Hamm could write Williston a $200 million check and not even notice it.
Original Post

The Bismarck Tribune is reporting:
North Dakota’s top oil regulator says the current slowdown in oil drilling “is not a bust by any stretch of the imagination” but will put a strain on state revenues in the next two years.
Really? How bad is it? Only $100 million more than what was projected.
Oil tax revenues helped North Dakota close out the 2013-15 biennium that ended June 30 with a $699.7 million balance in the state’s general fund, or about $100 million more than what was projected when the Legislature adjourned in April, according to preliminary figures from Office of Management and Budget Director Pam Sharp. The final balance will be available next month, she said.
What about flaring?
Department of Mineral Resources Director Lynn Helms also said low crude prices could prevent the state from reaching its goal of reducing flaring to 10 percent by October 2020 because natural gas processing projects have been suspended as the price of natural gas liquids has followed oil prices down. Eighteen percent of the state’s gas was flared in May.
The state is still receiving about 20 drilling permit applications daily, a “fairly rapid” pace.
The monthly dockets?
The state Industrial Commission was hearing about 185 to 200 oil and gas well cases per month in October and is now hearing about 100 cases per month, similar to 2009-2010 levels, while permitting numbers are back to 2011-12 numbers.
You know, awhile back the state paid a lot of money for an outside contractor to study the future of North Dakota based on oil. It's too bad the contractor did not provide data based on $50-oil. I think the contractor used $100-oil as the floor.


Later: I didn't think I could find that study referred to in the last paragraph above, but here is the study, and the comment I placed when posting that study:
The most glaring short-coming (obviously one can say this in hindsight), KLJ did all their studies based on three price-points for oil: $70/bbl; $85/bbl; and, $100/bbl.
In hindsight, they needed to take this to $50/bbl which is very possible for the next two to three years. (It is very possible but very unlikely.)
$50-oil won't shut down the Bakken but it changes the economic picture and the impact on North Dakota dramatically. In fact, the impact with $50 oil might be greater than if oil goes to $150 for the next five years. The contractor was lucky to complete this study by September, 2014, before the plunge in oil prices.  

High Oil Production, Low-Price Environment Due To Bakken Mega-Fracks -- Mike Filloon -- July 27, 2015

Tweeting now: US gasoline price ($2.75) at 10-week low, diesel ($2.72) lowest since Oct 2009.


This article will no doubt be archived by SeekingAlphaI've also posted lengthy notes on this article to help me understand the Bakken.
The summary bullets:
  • lower rig and completion numbers have not caused a rollover in U.S. oil production
  • marked improvements in well design plus high-grading have been very effective in producing more resources per foot
  • mega-fracs are also increasing production in adjacent wells through communication
  • given the change in U.S. oil well economics, we may need to retest 52-week lows to get meaningful production off the table
  • new well designs have changed the current decline curve, further skewing U.S. production estimates
There are more reasons, but these are the general beliefs. If fewer completions are occurring and depletion rates are high, why has production not rolled over? Many of the reasons are well known, including high-grading and lower oil service costs. Newer well designs skew data as depletion continues to decrease.
This cannot be emphasized enough, newer well decline rates are very low and cannot be compared to historical averages. Recent completions also produce more oil. When oil prices fell, operators moved quickly.
Exploratory programs decreased and rigs focused on core acreage. This includes the Nesson Anticline of the Bakken, Gonzales and Karnes counties of the Eagle Ford and Midland County of the Permian. There are other areas, but this provides a general idea of current core plays.

The Tuscaloosa and Eaglebine have suffered, as payback times can take several years.
Operators had rigs under contract, so they did what they do best. They started drilling holes. By moving quickly, they were able to add locations waiting on completion. Operators planned to let the rigs go after the contracts were up.
This left a huge "fraclog" of 4,000 to 5,000 wells. Wells drilled but not completed are considered part of an operator's inventory. By waiting, completion costs decrease, as do well costs. An operator may wait for higher oil prices. Last year the fraclog average was just 400 to 800.

It's Only A Mater Of Time -- July 27, 2015

Earlier today I posted a link to a contributor's article over at Seeking Alpha, "oil prices will rebound."

Well, of course, it will. The question is when.

If the drillers trust the EIA estimates, the rise in the price of oil could come sooner than some folks think. The tea leaves suggest this autumn, October - December, 2015, will be a most key period to watch.

The graph below was taken from the linked article. There are so many data points / story lines, but I think I noted the most important ones on the graph.

It is interesting to note that prior to the Bakken boom, there was a relative global supply shortage of world liquid fuels. The surplus happened quickly, much more quickly than some folks forecast. I'm not going to look for the source but there was an article out today in which an analyst actually admitted they did not see it coming (they must have been listening to Jane Nielson).

When the Bakken boom hit its stride, global surplus was striking -- look at those high bars between 4Q14 and 2Q15. We had not seen bars that high in years, and I bet we had not seen a string of such bars in decades.

By early next year, we may have a surplus of less than 500,000 bopd -- globally. That's less than half what North Dakota produces daily, and probably less than a quarter of what North Dakota is capable of producing.


Another asset sale? 

A Note To The Granddaughters

I'm working on several "projects" right now. Most of them have to do with reading, reading about the history of Santa Fe Railroad as told in The Harvey Girls; re-reading closely This Side Of Paradise and Tinker, Tailor, Soldier, Spy; and three books on evolution.

With regard to the latter, I think a lot of adults, including me, consider the Dinosaurs interesting, but not compelling; something for pre-teen boys to be interested in, but not much more than that. Having read for the first time one new book, and re-reading very closely two other books, I am convinced that a summer of concentrated study of the dinosaurs by a ninth-grade student would serve that student well for high school biology (generally a high school sophomore class) and Biology 101 and Zoology 101 as a freshman and then sophomore, respectively, in college.

A concentrated study in Dinosauria will result in a better understanding of taxonomy, physiology, anatomy, evolution, and paleontology. The neat thing is that pre-teen boys (and girls?) are already pre-wired to be interested in dinosaurs for some reason. Throw in a couple of the Jurassic Park movies, and maybe even Pixel's Toy Story, and it wouldn't take a lot to keep that curiosity running.

These are some very random thoughts after reading about Dinosaurs for the past two weeks.

On the road from one-celled organisms to humans, there were a few huge forks in the road, some huge events, that made all the difference in the world.

Of course, we start with the Cambrian explosion (Stephen Jay Gould's Wonderful Life).

From my perspective, the next huge evolutionary leap was the ability of animals to lay eggs on dry land, coming out of the seas. That was a huge leap.

The amphibians had their fifteen minutes of fame. They played a critical role getting us from the sea to the dry land, but after that role, their fame was over. Sure, they survive as frogs but their evolutionary purpose has been served.

Once animals could lay eggs on land (amniotes), another division occurred: the synapsids (mammals, for the most part) and the non-synapsids, the largest group being the diapsids ("reptilia" for the most part).

Of the five great chordate divisions (fish, amphibian, reptile, bird, and mammal), the "reptilia" division is the messiest. Everyone has trouble with "reptilia." It was the reptiles' great fortune that they continued to evolve; otherwise they, too, would have been like the amphibians, having had their 15 minutes of fame.

It is interesting how long ago he evolutionary split between future reptiles and humans took place: the amniote synapsid-diapsid split took place sometime in the Carboniferous/Permian period, well before the Age of Dinosaurs.

The reptile lineage ultimately led to Dinosuria. Interestingly, the Crocodylia broke off even before Dinosauria. The history of Crocodylia really goes back a long way.

The Dinosauria lineage completely disappeared except for one group of dinosaurs: present-day birds.

So, with just a few huge breaks in the road, among the chordates, it really comes down to fish, mammals and birds today. And if one is not ocean-centered, it's pretty much mammals and birds.

There are / were no marine dinosaurs. Those "things" that look like ocean-going dinosaurs were reptiles, not dinosaurs.

By the way, the "definition" of a dinosaur is any organism, alive or dead, that can trace its history back to the common ancestor of the Triceratops or the birds. I thought that interesting.

If the first big fork in the road was the Cambrian explosion, and the second big break for mammals was the success of amniotes (laying eggs on land), the third huge break for mammals was the demise of the dinosaurs at the end of the Cretaceous period, when the big meteor is said to have hit and formed the Yucatan Peninsula (Mexico), wiping out the dinosaurs.

It turns out that well before the first dinosaur ancestor was even around, little mammal-like reptiles were evolving. When the dinosaurs were at their peak, underfoot and in burrows were more evolved mammal-like reptiles and mammaliaforms.

It appears that their small size and their burrowing saved them from the meteor. Specifically, one Cynodont, very mammalian, that burrowed and survived the meteor was Trinaxodon.

For me, three great events between one-celled organisms and humans: Cambrian explosion, egg-laying on land, and the survival of the burrowing "mammal" when the meteor hit.

Compared to those three events, all the rest of evolution was "easy."

Another Photograph Of The Statoil Trust Wells West Of Williston, North Dakota -- July 27, 2015

As promised, here is the fourth of several photos that will be posted over the next several days. The first batch of photos will be of the Statoil Trust wells a few miles west of Williston. This 5-well pad is just east of another 4-well pad in the same section.

A huge "thank you" to the reader for sending these photos.

More On Re-Fracks -- July 27, 2015

More on re-fracks from that article over at Platts:
Many industry watchers were skeptical that refracturing technology was developed enough for wide-scale application on horizontal wells, which have gained momentum in the shale revolution since the early 2000s. But new technologies that can better pinpoint the areas of left-behind oil and gas from the original fracturing are being rapidly developed and oil service companies are betting big money on it.
For example, in recent weeks, Halliburton released a new reservoir evaluation tool, while Baker Hughes, the third-largest oil services company soon to merge with Halliburton, has debuted a well integrity evaluation tool.
For example, microseismic analysis and state-of-the-art tracers to monitor where proppants are directed can be applied to refracs. Rock quality varies between basins and requires different approaches. Proppants are typically sand or ceramic to hold fracs open and allow greater hydrocarbon flows.
Since often 10% or less of a well’s hydrocarbons are captured the first time around, many in industry look to refracs as a relatively inexpensive way to hike output — particularly at a time of lower oil prices, since refracs typically run around 25-30% of the original well’s $6-$8 million price tag.
In the last 10 days, the two largest oilfield service providers indicated they were preparing for a wave of refracs.
Wow, look at all those data points:
  • first, though, I doubt the HAL-BHI merger will be approved
  • North Dakota Bakken, I believe, has the world's largest micro-seismic array
  • as much as 10% of the OOIP recovered first time around. Really? We were told early on that the Bakken operators were getting only 1 - 3% first time around but I suggested early on it was much more than that; subsequently, some drillers suggest as much as 8% first time around, and maybe even that is too low with new completion techniques
  • in the last 10 days, the two largest oilfield providers indicated they were preparing for a wave of refracs
This comes on top of the 925 wells that need to be fracked for the first time in the Bakken.

This is going to be incredibly interesting to see play out.

By the way, did you all see the recent quote that the breakeven point for Bakken oil in the Watford City area is $28/bbl? 

Let's See Where This Goes -- July 27, 2015; Cost Of Intermittent Energy

Penn Energy is reporting: a nuclear power plant in Missouri is shutting down over a "non-emergency" leak.
The Ameren Corp. nuclear power plant in central Missouri was shut down for the second time in eight months Thursday after a "non-emergency" leak was found in the reaction control system.
The shutdown occurred at 1:15 a.m. at the plant near Fulton.
Ameren officials are investigating the cause. Trammel said it was unclear when the plant would restart.
This is a 1,900 MW power plant.

Presidential-wanna-be Hillary Clinton wants to replace this plant with solar panels. At $3 million / MW, the cost to replace this nuclear plant with a solar plant would be $3 million x 1,900 = 57 with 8 zeroes, almost $6 billion. Okay. Whatever. At $4.5 million / MW (see below) = almost $9 billion. Okay. Whatever. [I often make simple errors in arithmetic and my calculator doesn't always have enough zeroes when it comes to solar energy costs.]

From google: As of November 2014, Topaz Solar Farm was the largest PV solar plant in the world at 550 MW. The Desert Sunlight Solar Farm is a 550 MW solar power plant in Riverside County, California. Other large plants are under construction.

The Topaz Solar Farm supposedly cost $2.5 billion ($4.5 million / MW). The develop had to acquire 25 square miles and then went back and acquired another 640 acres.  

Any electricity produced by this plant has to have a "conventional" power plant for a) night-time hours; b) cloudy days; c) two to four hours of start-up time every morning when the solar panels are coming on line. 

By the way, speaking of high-cost solar energy. Does anyone remember this story? -- Where Tim Cook (Apple) paid $6.5 million / MW solar power, this was just earlier this year:
It was just announced this afternoon, apparently during Tim Cook's presentation, that Apple is building another 130 MW solar farm to power in central California. Forbes is reporting
First Solar said Tuesday it’s signed a 25-year contract with Apple to deliver solar electricity from a yet-to-be-built project in central California.
Apple “has committed $848 million” for 130 megawatts of energy from California Flats Solar Project in southeast Monterey County, said a press release.
$848 million / 130 MW = $6.5 million / MW.  Disclaimer: you may want to check my arithmetic. I often make simple arithmetic errors. But the story says $848 million for 130 MW of energy; if that's correct, and if $6.5 million / MW is correct, that's horrendous by anyone's standards. See story below. But again, I could be wrong. Deserve Sunlight is costing not enough twice $848 million and is getting way more than 130 MW.

So Much For All That Hand-Wringing Over Honeybee Colony Collapse; North Dakota Clear Winner (Again) In Honey Production -- July 27, 2015

From Carpe Diem: US honeybee-colony numbers are now at a 20-year high and US honey producton is at a 10-year high with a 19% increase in production last year.

Source here.  

I have many posts on North Dakota honey production, but this post will probably become the main post to track updates.

July 27, 2015: honey update from USDA, March 20, 2015, data points:
  • 2014: US honey production up almost 20% over 2013
  • 2014: total colonies up 4 percent over 2013
  • 2014: honey prices set a record high in 2014, up 1% from 2013
North Dakota led the nation in number of producing colonies: 480
  • California: 330
  • South Dakota: 265
  • Florida: 220 
  • Montana: 159
North Dakota trounces all other states in honey production: 33 million lbs
  • Montana: 15 million lbs
  • Florida: 13 million lbs
  • California: 11 million lbs
  • Minnesota: 8 million lbs
  • Texas: 6 million lbs
This explains the "Montana" phenomenon: Colonies which produced honey in more than one State were counted in each State where the honey was produced. Therefore, at the United States level yield per colony may be understated, but total production would not be impacted.

Monday, July 27, 2015

Before doing anything else today: check out the photos of the 18-well super pad on the Jeffrey Ranch.

Re-Fracks: Platts is reporting:
If at first you don’t produce, frac, frac again. While hundreds of North American wells remain unfinished due to low oil prices, some operators are embracing technology to refracture horizontal wells in an attempt to eke out more production at a fraction of the cost.
For years, consultants and some oil companies had claimed that the technology, which has been used frequently on vertical wells, wasn’t quite ready to be deployed horizontally.
That may be changing. The drive to tap a potentially vast market for hydraulic refractures of wells — popularly called “refracs” — is getting a shot in the arm as oilfield service companies tout new technology and create what may be the next big industry trend during the current downturn.
“Hundreds of refracs are planned in the US for this year alone,” said Tim Leshchyshyn, president of FracKnowledge, which is building what he said will be industry’s only refrac database.
Although refracs have been performed on thousands of vertical wells for decades to coax more oil and gas bypassed in original completions, they have been less prominent on horizontal wells. Just a few hundred refracs have been tried on horizontals.
Tweeting now: Nigerian oil union says, 'exploration activity has been greatly recessed by the challenge of funding the operating budget' -- #NNPC. Was Nigeria the first Saudi-engineered casualty in the oil war?

Also tweeting now: Algeria's Sonatrach raises August official selling price of Saharan Blend crude oil loading by $0.65/bbl to DatedBrent plus $0.45/bbl.

Also, also tweeting now: Mexico crude oil exports at 1.048 mil b/d in June, down 2.5% on year.

Active rigs in North Dakota:

Active Rigs73193207182136

RBN Energy: the cycle of Canadian crude production and discounts.
Western Canadian Select (WCS) – the benchmark for Canadian crude sold at Hardisty in Alberta fetched just $32.29/Bbl on Friday (July 24, 2015) down 60% from $81.34/Bbl a year ago in July 2014. That year has seen big changes in the U.S. oil market with drilling rig cutbacks and declining new production rates. The challenges for Canadian producers have not changed much in the short term – with transport capacity to market still top of the list. Trouble is that every time transport congestion occurs it pushes price discounts higher and lowers producer returns. Today we discuss the relationship between Western Canadian crude production and prices.
SeekingAlpha contributor: oil prices will rebound. (SeekingAlpha will likely remove this article and archive it for subscribers only at some point in the future.)

Asset Sale

Goodrich Petroleum announces sale of some Eagle Ford assets.
Goodrich Petroleum announced that it has entered into a definitive agreement to sell its proved reserves and associated leasehold in the Eagle Ford Shale in LaSalle and Frio Counties, Texas for $118 million.
The Company is retaining approximately fifty-eight percent (~ 17,000 net acres) of its undeveloped leasehold in the play for future development or sale. The asset being sold produced an average of approximately 2,850 barrels of oil equivalent per day (~75% oil) during the first quarter of 2015.
The Company expects to book a gain of approximately $50-60 million on the sale at closing after factoring in customary closing adjustments. The Company plans to pay off its bank revolver and retain the difference in cash from the sales proceeds.Two data points of interest:
First data point: this article did not say how many net acres were sold (unless I missed it), but working backwards, it sounds like the original net acres amounted to about 30,000 - 17,000 = 13,000 acres sold for $118 million or about $9,000 / acre.

Second data point: note that the production is about 75% oil which is the number I use for the Eagle Ford; in contrast, the Bakken is upwards of 95% oil depending on location.

Oil Groups Have Shelved $200 Billion In New Projects

Financial Times. And many of these are off-shore projects that will take many years to develop once the price of oil starts to make them economical. All that talk about drilling off-shore of the United States certainly seems moot now.