Proppants -- Random Note -- May 11, 2021

See this note for background.

From this link studying proppant and shale, Rock Mechanics and Rock Engineering, 54, 2233 - 2248(2021):

The technology of cross-linked fracturing fluids and proppant with a larger grain diameter of 0.850 ÷ 0.425 mm is usually used to fracture the rocks with an increased content of clay minerals and increased plasticity (Rickman 2008). 

Fracturing fluid used in our experiment was crosslinked natural polymer 30# (Fig. 6b). The composition of the fluid was as follows: tap water, biocide, gelling agent—natural polymer (guar) in powder 3.6 kg/m3, clay minerals stabilizer and clay swelling inhibitor, nanoemulsion, pH buffer, crosslinker (boron compounds), 2.0 l/m3, viscosity breaker, 2.4 l/m3. 

As proppant material—intermediate strength ceramic proppant ISP 20/40 was used. Proppant grain size was between 0.850 and 0.425 mm; mean grain size was 0.673 mm. Bulk density of proppant was 1.89 g/cm3. The proppant have an average sphericity of 0.88 and an average roundness of 0.85. 

From this link on proppants: 

The size range of the proppant is very important. 

Typical proppant sizes are generally between 8 and 140 mesh (106 µm - 2.36 mm), for example 16-30 mesh (600 µm – 1180 µm), 20-40 mesh (420 µm - 840 µm), 30-50 mesh (300 µm – 600 µm), 40-70 mesh (212 µm - 420 µm) or 70-140 mesh (106 µm - 212 µm). When describing frac sand, the product is frequently referred to as simply the sieve cut, i.e. 20/40 sand.

8 - 140 mesh: 106 µm - 2.36 mm
16 - 30 mesh: 600 µm - 1180 µm
20 - 40 mesh: 420 µm - 840 µm
30 - 50 mesh: 300 µm - 600 µm
40 - 70 mesh: 212 µm - 420 µm

1,000 nanometers = 1  µm

Re-Posting: Innovations In The Oil Patch -- Why Tier 2 Locations Can Evolve Into Tier 1 Locations -- May 11, 2021

See this post.

Re-posting this portion of that post:

Updates

Later, 6:29 p.m. CT: and there's more -- 

If you Google 'nano proppants shale',  you may see several articles describing this topic ... just one more of countless innovations that continue to emerge in the upstream segment of this industry.

It was just a few years ago that 'micro proppants' were introduced ... 200 to 400 mesh, ultra tiny particles that entered and scoured fissures and allowed the larger 100 mesh to enter and prop the newly-formed pathways. 

Now, nano particles, described as 1,000 mesh ( which are actually too tiny to be described in 'mesh'  terms ), are being employed. 

Some of this material is - literally - dust from crushed granite.

The discovery/improvement/refinement of so SO many aspects of this industry is nothing short of astonishing.

Later, 2:57 p.m. CT: more on Monobore drilling from the reader who sent the notes below --

In the Bakken (at least up to a few years ago), and many other shale basins,  a large 13-inch steel casing would be emplaced/cemented down to 300 feet or so ... beyond the water table.

Then, smaller 9-inch casing would be emplaced/cemented down to about 1,900 feet depth. 

From there, still smaller (7 inch/5 inch) casing would be installed/cemented down to the final vertical depth (10,000 feet) or out to the end of the lateral (20,000 total feet).

The biggest reason for this telescoping configuration is to effectively control the bottom pressures (3,500 psi up to 10,000 psi) throughout  an unbroken metal 'straw' right up to the surface.

Monobore drilling can be utilized when the recognized formation's bottom hole pressure is low enough so that these expensive casings/cementing are not needed.

The Niobrara (Colorado) is somewhat  shallow (~7,500 feet) with relatively low pressure. (This is one reason why Niobrara wells produce comparatively small amounts of oil per well). 

If state regulators allow, and operators believe casing is not needed, a drill rig will go from spud to TD in a single run which can be both faster and cheaper than standard drilling. [Comment: it's interesting - operators can drill the vertical in one day, the curve in twelve hours, and the lateral in three days -- I think that's the gold standard -- doesn't always happen, obviously, but I've reported several such wells.]

Some operators in shallow Permian formations have also  done this, but the entire approach gets very little publicity.

Later, 1:08 p.m. CT: a reader noted the information about how quickly the lateral was drilled. The writer added this: 

Expanding upon the ~3,000 foot per day lateral drilling situation ... To acknowledge how this impacts the economic viability of 'shale' wells throughout the country would be to state the obvious. Amongst other effects, this continues to expand the productive footprint of all the basins across the country. (This, in direct contrast to the OMG, running out of sweet spots concept). -- Comment: yes, I've also suggested this helps move "Tier 2" sites into "Tier 1" sites.

Antero just drilled 12,118 lateral feet in 24 hours, a record. 

While their average is now over 7,500 lateral feet per day, several other operators routinely  claim three-to- four-thousand lateral feet per day as their norm.

Again, an astounding accomplishment.

As per Schlumberger's press announcement a few weeks back (4/23/2021), they worked with a Niobrara operator who drilled a  >21,000' MD well on one run, using the so called Monobore approach which greatly reduces time and cost while  enabling expanded Artificial Lift options. -- Comment: I had not heard of the Monobore technology but a quick google search suggests this technology was developed for off-shore drilling and then found utility in very, very deep onshore drilling. I could be wrong but that was the impression I had.

The unceasing march of innovation continues unabated.

Comment: this was clearly a two-edged sword for oil service companies like Schlumberger. Their technological improvements kept them competitive but their margins may have decreased due to less "time on site." 

Original Post

The Hess EN-Anderson wells are tracked here. 

The well:

• 36603, 3,416, Hess, EN-Anderson-LE-156-94-1820H-11, 33-061-04514, Manitou, t11/20; cum 126K 3/21;  227,901 bbls water; 32 stages; 11.932 million lbs proppant; from the file report:
  

• spud date: June 19, 2020
• cease drilling: June 26, 2020 (let that sink in)
• target: middle Bakken
• 2560-acre spacing
• logging services began: 9:20 a.m., June 20, 2020
• KOP reached: 5:35 a.m. June 21, 2020
• building of the curve began at 6:45 a.m. June 22, 2020
• middle Bakken encountered at 10,153' TVD, one foot low to the prognosis;
• curve TD: 10,502' MD at 3:49 a.m., June 22, 2020 (obviously a typographic error)
• either 3:49 p.m. June 22 or 3:49 a.m. June 23
• lateral began at 11:17 a.m. June 23, 2020
• TD: 8:50 a.m. June 26, 2020 (three days to drill the lateral)
• wellbore tracked throughout the middle Bakken for 100% of the lateral;

North Dakota Loess As A Potential Microproppant -- January 12, 2019

This link will probably load as a pdf on your desktop.

Loess: rhymes with "bus."

Where "small sand" might be too big for use as a proppant in some areas of the Bakken, perhaps a microproppant like loess might work.

From the linked article:

Some proppant manufacturers have introduced new microproppants with grain sizes equivalent to that of a human hair and with the consistency of rock flour.

Sediment particle sizes in this range fall into the silt size category, which is generally defined as sedimentary particles sized between 0.0625 to 0.0039 millimeters.

Silt is very common throughout the sedimentary surface geology of North Dakota and may be found as a component of all of the surficially exposed materials across the state including the glacial sediments found across most of North Dakota, within the individual sedimentary siltstone bedrock layers in southwestern North Dakota, or when transported and deposited by the wind as loess deposits, which can be found in varying thickness across the entire state.

Wow, think about that. 0.0039 mm. Take out a standard ruler and note how "thick" one millimeter is. Not divide that into "10-thousandths." That's incredibly fine sand. 

Right now, the natural sand being used is:

• 100-mesh
• small
• medium
• large 

From this site:

This may load as a pdf on your desktop, 100 mesh.

Mesh size at this link:

Whiting Bucks Trend: Reducing Proppant In The Bakken; Bakken Holds On To Top Spot Among IRRs -- Platts -- August 24, 2018

If I had time to read only one Bakken story today, this would be it. A huge thanks to Geoff Simon for spotting it and sending it on.

Link here. Data points:

• Whiting reduces frack sand by 30% per well
• reduces capex by about $400K per well
• Bakken holds on to top spot among IRRs -- "So, what don't you want." Link here.
  

But, wow, look at this:

Whiting is one of the largest producers in North Dakota's Bakken Shale where it holds more than 400,000 acres. In the company's Hidden Bench play, located in the core of the Bakken in McKenzie County, it has been able to reduce proppant by about 50% and still maintain similar rates of production. It discovered that it could achieve the same production levels on new wells using 7.3 million pounds of sand as it did with 15.2 million pounds.

If the only thing you have is a hammer, everything looks like a nail.

If you "work smart," you may not need a hammer.

This is an incredibly good article. Archived. 

Fracking, Proppant, And Water

Disclaimer: I often make simple arithmetic errors. 

This updates previous posts on the same subject.

This is mostly for newbies, but feedback from those in the field will tell me how far off I am.

This is my 30-second "elevator talk" regarding completion strategies in the Bakken right now.

Length of laterals:

• the standard is a "long lateral"; some call it an "extended reach";
• two sections "long"
• about 9,000 feet horizontally

Number of stages:

• 50
• less than 40 catches my attention; suggests something out of the ordinary; I check the sundry forms to see if there might be an explanation; below 20, "definitely" a failed frack
• up to 60, occasionally
• over 60, catches my attention

Water (gallons, data from FracFocus):

• 8 million to 12 million gallons; generally 10 million gallons
• less than 8 million gallons gets my attention
• up to 12 million gallons doesn't necessarily surprise me; 
• up to 20 million gallons definitely gets my attention

Water (by percent, weight, data from FracFocus):

• 86%
• below 84% gets my attention
• above 90% really gets my attention

Sand/ceramic (by percent, weight, data from FracFocus):

• 14%
• for all practical purposes, the difference between 100% and water volume by weight
• a very small percent of overall mix is the proprietary "cocktail" to help "lubricate" the movement of oil to the well bore
• generally about 14%
• above 16% gets my attention
• below 10% really gets may attention

Middle Bakken vs Three Forks

• perhaps the Three Forks requires less water, less sand/ceramic

Sand/ceramic per stage

• 10 million lbs / 50 stages = 200,000 lbs/stage

Sand/ceramic per foot (which most folks like to use)

• 10 million lbs / 9,000 feet = 1,100 lbs / foot (about half what they are using in the Permian, based on what Mike Filloon posts)

To determine amount of sand, until the official report comes out, using data from FracFocus:

• a gallon of water = 8.35 pounds
• calculate amount of water in pounds (e.g., 10 million gallons x 8.35 pounds = 83.5 million lbs)
• if weight of water in percentage is 86%, then 14% (by weight) is sand/ceramic
• ask yourself: if 86% is percentage weight of water in total frack, how much was total completion mix (water + sand/ceramic)?

• example:
• 86% of the total frack was water by weight
• water weighed 84 million lbs
• 86% of what = 84 million lbs 
• what = 84 / 0.86 = 97 million lbs
• continuing
• 14% of the total frack was sand/ceramic by weight
• 14% of 97 million lbs = 14 million lbs sand/ceramic 
• I think my method works but my thinking could be faulty
• This would be an estimation only

Checking my work:

• in my example, total frack mix (water + sand/ceramic) = 97 million lbs
• 86% of that was water, or 83 million lbs
• 83 million lbs of water / 8.35 pounds (per gallon of water) = 10 million gallons, and that's where we started 

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

Real World Example

Let's see how well the information above works. We will look at this well that came off the confidential list June 28, 2018, FracFocus data embedded:

• 30230, 1,006, Nine Point Energy, Simpson 151-102-5-8-4H, Elk, t1/18; cum 65K 5/18; taken off line as of 5/18 after strong production; FracFocus data: fracked 11/11/17 - 12/9/17; 13.291 million gallons of water; 91.46% water; sand, 8.2%;

Calculations:

• 13.291 million gallons x 8.35 pounds = 110.98 million lbs
• 91.46% of what = 110.98 million lbs
• total frack mix weighed: 121.3425 million lbs
• of that, 0.082 x 121.3425 = 9.95 million lbs sand
• 9.95 million lbs / 200,000 lbs = 49.75 = 50 stages

Let's look at the frack report in the NDIC file report for this well, #30230:

• 50 stages; 10.02 pounds sand (7 million lbs mesh; 3 million lbs medium)

 
 

Bakken Learning Curve Driving Production -- NGI -- November 18, 2017

A reader just sent me this link. It's an incredible story -- nothing new for regular readers, but worth noting. This story has been told in various media outlets for the past few days. I think the resiliency of the Bakken has surprised a lot of folks. I've been reporting on that in several different posts. It began with the most recent monthly production figures and Lynn Helms comments at the time.

The story is at NGI's Shale Daily. Articles here are often behind paywalls, but apparently this one is not, at least not yet. The headline: Bakken learning curve said driving well productivity gains.

Drilling productivity in the Bakken Shale, which is producing more than 1 million b/d of light sweet crude oil, is a byproduct of geology and the fact that North Dakota operators are further along the learning curve than in other U.S. onshore plays.

Compared to a six-year-old well on average, wells now produce about 70,000 bbl more in the seventh month of their life.

Operators also are having fewer issues with hydraulic fracturing (fracking) and well interference, he said. Water and sand volumes are higher this year than they were a year ago too, which indicates more fracking and longer laterals.

Helms believes the Bakken has remained at the cutting edge in technology applications, such as fracking techniques, lateral length and the drilling speed.

"Equally important is the fact that the Bakken, with the exception of the far northwestern corner of the state, is very overpressured, much more than many of the other major U.S. plays," he said. "This makes Bakken well productivity quite a bit higher due to the rock being so over-pressured."

As noted in an earlier post, we've not yet seen many of these 3-mile long laterals talked about in the article, but we should start seeing more of them this winter. Winter weather will impact drilling to some extent, and will probably impact fracking to a great extent.

We're currently in Bakken_2.0 but it's very possible we will move into Bakken_2.5 or Bakken_3.0 based on the adoption of these 3-mile and 4-mile laterals.

By the way, I'm not seeing the huge amounts of proppant being used in the Bakken compared to other onshore plays. By Bakken standards, the amount of proppant has increased, but it seems that operators are staying below the 10-million-lb threshold in most cases. It almost looks like they are increasing the number of stages but maintaining the amount of total proppant.

From FAQs:

85. Definitions for length of laterals. Based on stories being reporting November, 2017, it appears time to formalize the parameters for laterals of various lengths in the Bakken (laterals only, not total drilling depth):

• short lateral: 4,500 feet, one section
• long lateral: 9,000 feet, two sections
• extended long lateral: 14,000 feet, three sections
• super long lateral: 18,000 feet, four sections

Pullback In US Fracking Sand Use Pressures Producers -- Reuters -- August 16, 2017

Link here.

The lede:

U.S. shale oil companies are pulling back on the amount of sand they use to hydraulically fracture new wells, responding to rising prices of the material that are driving up costs.

Investors worry a slowdown in sand use, combined with new mining capacity coming online, could lead to a glut of the material and bring down prices. The worries have pressured shares of sand companies.

Sand prices soared in the last year as oil companies ramped up shale drilling and production.

But with crude prices below where they started the year, oil producers are employing new well designs and chemical agents that lessen the use of sand that represents around 12 percent of the cost of drilling and fracturing.

The Bakken was not mentioned. The last sentence:

Atlas Consulting's Salazar said of the major U.S. shale basins, only two - Haynesville and Eagle Ford - are pumping in more sand per well.

I started following this story in March, 2017, when it was being reported that operators were using increasing amounts of proppant (sand) to frack their wells. I was not seeing that in the Bakken so I was curious to track it. By late July, 2017, I had lost interest. I didn't see a lot of difference in the amount of sand being used, except perhaps in some EOG wells. EOG was clearly an outlier, but even EOG did not consistently use larger amounts of sand.

There are several other stories involving fracking that should also be addressed:

• workovers
• mini-fracks
• re-charging effect
• halo effect
• anecdotal: a refrack with only 5 million lbs of sand resulting in huge result (again, if accurate data)

Random Note: High-Intensity Fracks -- July 19, 2017

These wells will be tracked elsewhere, but note the number of stages and amount of proppant used in fracking. These wells were released from the confidential list on July 19, 2017:

• 27390, 918, EOG, Parshall 69-1820H, Parshall, 56 stages; 20.46 million lbs; 100 mesh, t1/17; cum 81K 5/17;
• 28401, 1,611, EOG, Parshall 153-1820H, Parshall, 49 stages; 14.5 million lbs; 100 mesh, t1/17; cum 57K 5/17;
• 29899, 1,045, Liberty Resources, ND State 158-95-16-9-5MBH, McGregor, 27 stages, 6.5 million lbs; large (40/70); t1/17; cum 66K 5/17;
• 29900, 1,070, Liberty Resources, ND State 158-95-16-9-5TFH, McGregor, frack data not available, t1/17; cum 63K 5/17;
• 29901, 1,257, Liberty Resources, ND State 158-95-16-9-6MBH, McGregor, 27 stages, 6.5 million lbs; large (40/70), t1/17; cum 86K 5/17;
• 29910, 1,038, Liberty Resources, ND State 158-95-21-28-6TFH, McGregor, frack data not available, t1/17; cum 86K 5/17;
• 32743, 1,723, Hess, HA-Grimestad-152-95-3031H-9, Hawkeye, 60 stages; 4.2 million lbs; large (40/70); small (30/50); t5/17; cum 11K after 8 days;
• 32094, 1,356, CLR, Kukla 7-16H, Chimney Butte, 4 sections, 56 stages; 25.9 million lbs, t5/17; cum 88K 7/17; 

See also this post.

Technology Redefining the Energy Sector -- US News -- July 13, 2017

Updates

Later, 1:48 p.m. Central Time: see second comment -- something new -- something I had not seen before --

When cumulative production is charted between wells with equal amounts of conventional proppant use, the ones with microproppant added show little gains at first, with a widening advantage as they reach the 1-year mark....

It...does not fit neatly into the current industry focus on maximizing early production as the testing suggests that the benefits of microproppant become apparent later in the life of a well.

Wow, now it's not just sand vs ceramic proppant, but the size of the individual "pellets." This is not a bit surprising but it does add one more variable to the mix. Good stuff.

Later, 1:44 p.m. Central Time: see first comment where there are some great links. This caught my eye since it really fits the original post:

Enhanced oil recovery from unconventional formations has been sought since unconventional development first began.

While recovery factors in conventional reservoirs commonly exceed 25%, unconventional development seldom recovers more than 9%.

There is, therefore, a tremendous amount of oil and gas still in place in unconventional fields, waiting to be recovered. 

Think about that. If current unconventional recovery is less than 9%, imagine what 12%, 15%, 18% might mean in the out years.

Original Post

I thought this was another one of those superficial articles. If so, I had planned to simply link at one of the earlier posts. Surprise, surprise. It's a very, very good article, but you have to read past the fluff.

From US News via Yahoo!Finance:

Technology has redefined the energy sector. The first thing investors should understand, says Reynolds, is how horizontal drilling and hydraulic fracturing technology has revolutionized the energy industry.

It used to be that oil companies were primarily explorers hunting for oil pockets they could tap and bring to market, and the potential of those fields was limited by the price of oil.

"The fields were discrete, so if there was 100 million barrels there would always be 100 million barrels," Reynolds says. "The value of that discrete field was simply calculated based on the price of oil."

The result was that oil companies were always on the hunt, spending billions each year in pursuit of the next oil field. Reynolds says the industry got a reputation for "destroying capital" as a result, since expensive deepwater exploration "didn't have high enough success rates to make for sustainable companies" and the high cost of extraction relied on perpetually high energy prices.

Now, technological advances like fracking allow oil companies to access massive onshore shale oil fields with greater ease and much lower investment. The volatility in energy prices will never go away, Reynolds says, but now "the only thing these guys need to worry about is getting the cost of getting that oil out of that shale lower and lower -- and over the 10 years this (fracking) industry has really existed, that's all they've done."

As a result, many investors are expecting North American shale companies to "grow 20 to 30 percent, or even more," Reynolds says. And since risk is lower than conventional oil companies thanks to cost controls, these shale companies look particularly attractive right now.

Note: over the 10 years this (fracking) industry has really existed. Exactly my numbers. Corresponds exactly with the EOG "discovery" well in the Parshall oil field in 2007. As Donald Trump, Jr, would say, "I love it."

We've talked about this on the blog numerous times.

When they first started fracking in the Bakken, they talked about recovery rates (we're talking primary production here) of 1 to 3 percent. Early analysis suggested they were getting significantly more production than 3 percent, and, in fact, Whiting was soon talking about 5 to 8 percent recovery.

Now, I think the new number is as much as 20% recovery (not yet, but apparently a realistic goal).

If the OOIP of the Bakken was 500 billion bbls, a 1% recovery rate meant 5 billion bbls of crude oil would eventually come out of the Bakken.  At 3%, it become 15 billion bbls. At 6%, it becomes 30 billion bbls. Regardless of the recovery rate, the later bbls are less expensive to produce than the earlier bbls. (Don't take this out of context; not all would agree.)

At 1 million bopd, one year, 365 million bbls, 10 years, 3,650 million bbls or 3.6 billion bbls of crude oil after ten years.

Over time, each additional bbl comes in at a lower cost. In conventional drilling, well, I'm starting repeat the article linked above.

Impact Of Changes To Mexican Heavy Crude Benchmark -- RBN Energy; Fracking Sand Update -- January 27, 2017

Updates

Later, 11:25 a.m. Central Time: that "canceled' meeting between POTUS and POMEX? Not so fast. They had an hour-long telephone call earlier this morning. I think folks need to put this whole North American "family" spat in context. One wonders who initiated the phone call.

Original Post

 

Futures: again, this has been quite fascinating, watching futures go from "red" to "green" but not by much; and, then all of a sudden, at 7:01 a.m. Central Time, futures jump from 4 to 29 points in early trading (CNBC). After GDP report comes out, Dow 30 goes "red."

CVX earnings: wow, huge miss. 22 cents forecast vs 64-cent estimate; shares down 3% on news;

First estimate 4Q16 GDP: 1.9% --  source here --  after report Dow 30 futures went negative. MSBNC: "tepid." On January 3, 2017, the "GDPNow" forecast:

The GDPNow model forecast for real GDP growth (seasonally adjusted annual rate) in the fourth quarter of 2016 is 2.9 percent on January 3, up from 2.5 percent on December 22.

Mexican stand-off: stories to follow --

• Trump's favorability ratings
• effect on the market
• is the "war of words" really needed?
• who blinks first?
• Vicente Fox: on CNBC, the reason US automakers almost collapsed -- "US workers make high-cost cars of mediocre quality" -- Vicente Fox will help move the discussion
• the "wall" -- deploy the drones 
• by the way: Trump's 20% on imported goods echoed GOP plan; chairman of House Ways and Means supports it; 

North Dakota reservations hope Trump's presidency makes a difference -- article over at Reuters. 

Proppacalypse: frack sand demand on fire in 2017 -- Rigzone. Mike Filloon predicted this at least a year ago. Data points:

• rig counts plummeted almost 75% during the last two years
• sand demand dropped off about 40%
• proppant use in the US will reach above 2014 levels despite diminished activity of 60% fewer rigs
• proppant intensity has increased more than 50% in the Permian, Eagle Ford, the Bakken, since 2014
• 2016 forecast: demand would be up to 200 billion pounds; that cap was met by the beginning of December; now, forecast for 240 billion pounds for 2018, double the annual peak of 108 billion barrels
• demand could drive sand prices at least 60% higher: to ~ $40 per ton range

Proppants 101: for newbies -- a primer on sand.

Fracking sand, some data points from linked posts above:

• when you see a 100-unit train carrying sand, that amount of sand will frack one Permian well, maybe five Bakken wells at most
• there are about 900 DUCs in the Bakken: wells drilled to depth; waiting to be fracked
• Harold Hamm (on CNBC yesterday -- January 27, 2017) said there was no shortage of sand 

New player in the oil patch: Bloomberg's take on the GE-Baker Hughes merger.

Baker Hughes: "only higher oil prices will spur international spending." Baker Hughes suggests oil prices must go up 15% to drive new investment. $53 x 1.15 = $61.

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

Back to the Bakken

Active rigs:

	1/27/2017	01/27/2016	01/27/2015	01/27/2014	01/27/2013
Active Rigs	38	47	154	187	190

RBN Energy: impact of changes to the Mexican heavy crude benchmark -- part 2.

A major component of the formula used to set the price of Maya—Mexico’s flagship heavy crude, and a key staple in the diet of many U.S. Gulf Coast refiners—was changed earlier this month, raising new questions about this important price benchmark for nearly all heavy sour crude oil traded along the U.S. Gulf, and points beyond. The change came as Maya production volumes continue to fall, and as Maya is facing increasing competition from Western Canadian Select (diluted bitumen) from Western Canada. Today we conclude a two-part series on Maya crude oil, the new price formula and its potential effects.

As we said, in Part 1, Mexico currently produces about 2.2 million barrels a day (MMb/d) of crude oil, about half of which (~1.1 MMb/d) is exported—three-fifths of which goes to the U.S.  P.M.I. Comercio Internacional S.A. de C.V. (PMI) is the crude oil marketing entity of state-controlled Petróleos Mexicanos (PEMEX) and manages the export of four distinct quality grades of crude oil, ranging from Altamira (an asphalt grade) and Maya on the lower end of the quality spectrum, to Isthmus in the middle, and Olmeca at the higher end. Most of Mexico’s crude oil exports to the U.S. Gulf Coast are Maya blends, as Mexico tends to retain most of its lighter grades (Isthmus and Olmeca) for domestic refinery consumption. However, the share of Maya exports headed for the U.S. has been falling fast—from 78% in 2013 to only 44% through the first nine months of 2016; the share of Maya bound for Europe has more than doubled over the same period and the share shipped to the Far East has more than tripled.

Canadian heavy sour crude oils such as WCS and Cold Lake are similar in quality to Maya but have historically been priced at significant discounts due to transportation constraints to reach the U.S. Gulf Coast. Should the Keystone XL Pipeline or other similar pipeline projects be constructed, the availability of these heavy sour crude oils in the Gulf Coast region could increase significantly, leading to more competition for Maya, more downward K factor adjustments, and higher volatility in the Maya price—all to the benefit of heavy-sour crude refiners. As previously discussed, PMI seems to be anticipating this eventuality and has been diversifying its Maya export destinations. Stay tuned for how these and other future events could impact the Maya pricing formula.

EOG Reports High-Volume Proppant Well -- 21 Million Lbs; "1.5 Section" -- 960-Acre Drilling Unit -- November 17, 2016

I track high-intensity fracks here. 

Note, 21 million lbs of sand, in a lateral that was not a "two-section lateral":

• 31248, 1,272, EOG, West Clark 104-0136H, Clarks Creek, middle Bakken, 36 stages, 21 million lbs, t5/16; cum 86K 9/16; drilling unit: 960 acres; TVD around 10,600 feet; TD, 18,185 feet; total lateral, 7,338 feet; target total, 7,338 feet (100%); KOP December 4, 2015; cease drilling December 8, 2015; from surface, well was sited in southwest corner of section 1-151-95; proceeded northeast and then northnortheast under section 1-151-95, ending just short of the halfway mark in section 36-151-95W (according to diagram on page 29 -- but it obviously ended in section 36-152-95).
• 21,029,167 lbs; 36 stages; 7,338 feet: 584K lbs/stage; 2,866 lbs/foot

********

NDIC File No: 31248     API No: 33-053-06955-00-00     CTB No: 231247
Well Type: OG     Well Status: A     Status Date: 5/17/2016     Wellbore type: Horizontal
Location: LOT4 1-151-95     Footages: 250 FSL 835 FWL     Latitude: 47.920333     Longitude: -102.786881
Current Operator: EOG RESOURCES, INC.
Current Well Name: WEST CLARK 104-0136H
Elevation(s): 2204 KB   2174 GR   2177 GL     Total Depth: 18185     Field: CLARKS CREEK
Spud Date(s):  11/8/2015
Casing String(s): 9.625" 1815'   7" 10844'  
Completion Data
   Pool: BAKKEN     Perfs: 11254-18092     Comp: 5/17/2016     Status: F     Date: 5/18/2016     Spacing: ICO
Cumulative Production Data
   Pool: BAKKEN     Cum Oil: 86051     Cum MCF Gas: 228034     Cum Water: 151593
Production Test Data
   IP Test Date: 5/18/2016     Pool: BAKKEN     IP Oil: 1272     IP MCF: 2832     IP Water: 2566

Monthly Production Data

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	9-2016	30	14119	14517	19523	51368	48082	2802
BAKKEN	8-2016	31	16194	16000	20674	43318	36229	6621
BAKKEN	7-2016	31	20572	20605	26989	52672	45962	6210
BAKKEN	6-2016	30	19013	18998	41943	46031	44512	1140
BAKKEN	5-2016	15	16153	15781	42464	34645	32027	2384

*********

Frackers Surprising Themselves How They Keep Squeezing Out More Oil Per Rig -- August 3, 2016

Updates

August 5, 2016: from Bloomberg, "the next shale boom will be built on sand." It is reported in the original post below.

Original Post

Reuters/Rigzone link here.

Nimble U.S. shale oil producers continue to show an uncanny ability to squeeze more and more crude from new wells, allowing them to do more with less as they try to weather another dip in oil prices to $40 a barrel.

Comments from Noble Energy, Devon Energy and Occidental Petroleum on Wednesday were significant because only six months ago many analysts were fretting that shale producers had hit a wall after slashing costs and lifting well output by as much as 50 percent since the steepest price crash in a generation started in mid-2014.

Now, while acknowledging that most oilfield services costs cannot fall further, these companies say they are still seeing output gains from improved well designs and fracking techniques. The rising well output means they can produce more oil with each dollar spent. This could help them survive the latest slump in oil prices back to multi-year lows after a partial recovery brought crude back up to about $50 a barrel.

Initially, Noble expected to get 390,000 barrels of oil equivalent per day (boe/d) this year on spending of $1.5 billion. Now it expects to spend less and produce 415,000 boe/d.

Lately the company has experimented with fracking wells using 3,000 pounds of sand per foot, several orders of magnitude greater than frack jobs a decade ago.

Companies have also been fracking even more parts of rock around a wellbore, boosting output. At Occidental, Chief Executive Vicki Hollub said 2016 production would now be at the high end of its forecast for a 4 to 6 percent increase from 2015 levels of 652,000 boe/d - without raising budgeted spending of $3 billion.

9,000 feet horizontal x 3,000 pounds/foot = 27 000 000. 27 million lbs of sand. Hmmmm..... not seeing nearly that much in the Bakken. 

415,000 boepd x 365 = 151,475,000 boe over a calendar year. $1.5 billion / 151,475,000 boe = $9.90 / boe in production costs. Hmmmm....

Note: I often make simple arithmetic errors. Don't make any financial, investment, travel, relationship, or job decisions based on what you read here. If this information is important to you, go to the source. 

And then look at this from Bloomberg/Rigzone:

Amid the gloom and doom that’s set in all along America’s shale fields these past two years, there has been one small, but consistent, bright spot.

Sand, it turns out, is a much greater tool in hydraulic fracking than drillers had understood it to be.

Time and again, they’ve found that the more grit they pour into horizontal wells -- seemingly regardless of how extreme the amounts have become -- the more oil comes seeping out.

The message from drillers is "more, more, more sand," said Sean Meakim, an oil-services analyst at JPMorgan Chase & Co. "All of the numbers are going up and they’re going up dramatically."

On a per-well basis, sand use has doubled since 2011, climbing to nearly 8 million pounds.

It’s this growth that’s sent the stock prices of the country’s four publicly traded sand miners surging more than 90 percent this year. True, overall sand usage in the fracking industry is still way down from the 2014 peak -- more than three-quarters of America’s drilling rigs, after all, have been idled since oil prices collapsed -- but the per-well increases have analysts and investors betting that the sand industry will boom again as soon as fracking activity starts to pick up even a little bit.

I can't say for sure, but this well might have set the record for most sand used in fracking in the Bakken:

• 22487, 67, EOG, Hawkeye 02-2501H, 69 stages, 27.6  million pounds, according to a reader, extended long lateral (3 sections long); t12/13; cum 623K 6/16; it's been off-line the last couple of months due to fracking / completions in neighboring wells; before that, it appears that EOG cut back on production from this well.

Generally, it appears operators are drilling long laterals (two sections, about 9,000 feet) and using between 1 million and 8 million lbs proppant. I am somewhat surprised by the relatively small amount of sand currently being used in the Bakken. There may be a couple of story lines there. 

Filloon's Update On The Bakken: Focus On Proppant -- April 19, 2016

Summary:

• ceramic proppant demand is down 49% year over year
• operators continue to increase proppant per well, but are choosing to use more frac sand
• a large number of mega-fracs use little to no ceramic proppant
• the current ceramic proppant market is oversupplied and higher oil prices probably will not right the industry

Archived.

Of the 233 wells in North Dakota using 8 million lbs of proppant or more only five used any ceramic proppant. Some of this is skewed due to EOG being the main Mega-Frac producer, but it speaks volumes when we see this many use only sand.

Wednesday, July 1, 2015 -- Part I: The Bakken

IPs for wells coming off confidential list today have been posted.

Active rigs:

	7/1/2015	07/01/2014	07/01/2013	07/01/2012	07/01/2011
Active Rigs	76	189	192	215	172

RBN Energy: natural gas from Texas to Mexico.

Natural gas exports to Mexico are on a tear, and there’s every reason to believe the market will continue to grow. In essence, parts of the Eagle Ford and Permian Basin are becoming the go-to fuel source for new power plants and industrial facilities south of the border, as evidenced by a Howard Energy Partners plan to build new, connecting pipelines to deliver large volumes of gas directly from South Texas to emerging demand centers in and around Monterrey, Mexico. Howard’s also been addressing some of Texas’s gas gathering and processing needs. Today, we consider the latest plan to add gas pipeline capacity across the Rio Grande.

Despite Mexico’s long-term potential as a world-class natural gas producer, the U.S.’s vecino del sur (that’s “southern neighbor” to our monolingual readers) is becoming increasingly dependent on Texas, New Mexico and Rockies gas to meet its fast-growing requirements. 

Mexico’s most promising shale plays (the Burgos and Sabinas basins just south and west of the Eagle Ford) are said to be geologically complex (in other words, tough to figure out from a gas-extraction perspective). These areas also lack the road and water infrastructure that development would require, and (thanks to drug-cartel gangs) they can be pretty risky places to do business. So for muchas mañanas to come, U.S. gas producers will be playing a critical role in supplying the fleets of new gas-fired power plants that the Comisión Federal de Electricidad (CFE, Mexico’s state-owned electric utility) and independent power companies are building and planning.

Mexico’s appetite for imported gas has been growing even more quickly than many had predicted; according to the U.S. Energy Information Administration (EIA), U.S. producers sent an average of 2.57 Bcf/d south of the border in March 2015 (the latest month for which those figures are available), up 37% from the 1.87 Bcf/d exported in March 2014. (According to a published report, Mexican imports spiked to 3.4 Bcf/d on June 12, 2015 --57% higher than the 2.17 Bcf/d average in June 2014—and it’s widely expected that deliveries of U.S. gas to Mexico will surpass 4.5 Bcf/d over the next few years.)

Seems like Mexico can’t build new capacity from the U.S. quickly enough; as soon as a new pipeline comes online, it gets filled and U.S. gas export levels ratchet up to another new high. (Kinder Morgan’s new Sierrita Lateral from near Tucson, AZ to the Mexican border being a recent example.)

That brings us to Howard Energy Partners (HEP), which has been artfully assembling a gas gathering, processing and transmission network that—with HEP’s latest plan—will extend deep into northeastern Mexico’s state of Nuevo León, whose capital is Monterrey (Mexico’s third-largest city).

Over the past four years, HEP (which is “financially partnered with” EnLink Midstream and Alinda Capital Partners) has built up significant but geographically focused midstream gas assets in South Texas, including its Webb County, TX hub system in the southern Eagle Ford (near the Mexican border; Webb’s county seat is Laredo—hence our blog’s title). The system consists of more than 280 miles of gathering pipelines (for rich and lean gas), and 200 MMcf/d of gas processing capacity (at HEP and EnLink’’s new Reveille plant; black plant icon on the map); producers Escondido Resources II and Laredo Energy hold long-term gas gathering and processing contracts at Reveille.

Coincidentally, Seeking Alpha had a similar story yesterday:

• Natural gas exports to Mexico are expected to increase by over 2.1 bcf/d in 2015 to about 4 bcf/d.
• The first US LNG export facility (Sabine Pass) is expected to go online at the end of 2015.
• Approximately 7 bcf/d of US LNG export capacity is already under construction. Most is expected to come online in late 2017 to late 2018.
• Approximately another 7 bcf/d in US LNG export facilities already have long-term delivery contracts. Experts believe they will make the financial decision to build in 2015 despite low oil. 

Fracking, from San Antonio Business Journal:

Six-year low crude oil prices may have decimated new drilling activity, but market indicators show there is a more intense use of frac sand in the new wells that remain in the Eagle Ford and other shale plays.

Mostly mined in Wisconsin and other northern states, frac sand is mixed with water and different chemicals to fracture shale formations in order to unleash oil and natural gas reserves.

A June 11 report from global investment bank Jefferies shows that overall demand for frac sand is down in 2015 due to low oil prices but its use per well has been steadily increasing over the past three years.

Jefferies reported that hydraulic fracturing wells in the United States currently use an average of 4.2 million pounds of frac sand per well but there is a "rising intensity" across different shale plays and that demand per well is expected to grow.

A recent report about frac sand by the Chicago-based Heartland Institute confirms the trend noting that silica sand made up 9.5 percent of fracking fluid a few years ago but can now represent up to 20 percent of fracking fluid during horizontal drilling activity.

Regular readers of the blog were aware of this for quite some time. For newbies, the history in North Dakota:

• at the beginning of the boom, open hole fracks with less than 500,000 lbs proppant
• operators took baby steps to one million lbs proppant
• Statoil surprised the industry with consistent early use of 4 million lbs of proppant which they still tend to use
• EOG blew the industry standard away when they started using 8 to 10 million lbs of sand (only) in 2014
• the record amount of sand EOG has used in one well is about 20 million lbs, and that was a simply long lateral (2014)

Great Article On Ceramics Over At Seeking Alpha -- April 16, 2015

Nice article in Seeking Alpha on ceramics:

FracFocus data reveals some troubling trends for the ceramics industry and for Carbo. Last year, significant investor attention was placed on Carbo when major customer Rosetta Resources switched to all-sand completions in the Eagle Ford. A review of the FracFocus database indicates further customer losses for the ceramics industry and Carbo.

Two of last year's major E&P mergers are having a significant negative impact on Carbo: Whiting's acquisition of Kodiak Oil and Gas, and Encana's acquisition of Athlon Energy. Both deals closed at the end of the fourth quarter, and their impact only began to be felt in the first quarter. These acquisitions are likely to have an impact similar in scale to the loss of Rosetta in 2014.

Based on FracFocus data, it is likely that Kodiak was one of Carbo's top ten customers. Kodiak used ceramics as its primary proppant. However, Whiting is primarily using sand. Whiting still uses ceramics for a portion of its wells in McKenzie County, but ceramics are typically no more than 30% of the proppant volume for those wells. With the exception of Kodiak's Polar acreage, Whiting is now primarily using all-sand completions on the former Kodiak acreage.

More:

Proppants are a key ingredient in the fracturing of oil and gas reserves. Proppants are the largest non-water ingredient in a typical frac fluid mix. Proppants keep the fractured oil and gas well "propped" open, allowing for oil and gas recovery. See Wikipedia for basic information. For a more technical understanding of the fracturing process, this Baker Hughes presentation is excellent.

There are three main categories of proppant: raw sand, resin-coated sand and ceramics. Raw sand is the cheapest and comes in several sizes and qualities. Ceramics are made from a variety of metal ores, and claim to offer superior strength and performance, but charge a premium price. Resin-coated sand is a hybrid, attempting to offer some of the benefits of ceramics, but at a lower price point. Major frac sand companies include Fairmount Santrol, US Silica, Hi-Crush Partners, and Emerge Energy Services.

And more:

According to PacWest Consulting Partners, overall proppant consumption on a per pound basis has been growing at a 30% CAGR heading into the current industry downturn. Increases in the total number of horizontal wells fractured, frac stages per well and pounds of proppant per stage have all contributed to this high rate of growth. However, raw sand has seen almost all of the growth, with resin-coated sand only having modest growth and ceramics volumes flat. Resin-coated sand and ceramics have both lost share in the number of wells using them and in the percent of proppant per well.

While ceramics cost more than ten times raw sand at the source, transportation costs disproportionately impact the price of raw sand. For example, Northern White Frac Sand costs between $60-$70/ton at the mine, but typically costs $120-$160/ton at the basin after rail transportation costs. In 2014, Carbo realized a price of $600/ton for its ceramic products. Thus, in basin pricing is typically 4-6x higher for ceramics.

Given the historical pricing disparity between sand and ceramics, most E&P customers have chosen to frac with sand. According to a Freedonia Group study, raw sand accounted for 81% proppant volumes by weight in 2013, and that likely increased to nearly 90% of proppant volumes in 2014, as frac sand continued to take share.

Much more at the link. This is one of the better articles I've seen on this subject; it's a keeper; it will be archived at the source.

Disclaimer: this is not an investment site. Do not make any investment decisions based on anything you read here or think you may have read here. 

Doesn't Sound Like Shale Is Going Away Any Time Soon -- Operators Stockpiling Sand; Investors Pouring Money Into Oil Funds -- October 21, 2014

Updates

October 21, 2014: just after posting the note below, Don sends me the link to this story. Reuters is reporting: investors are putting money into funds that track oil prices at the fastest rate in two years, betting that crude will rebound from a bear market.

The four biggest oil exchange-traded products listed in the U.S. have received a combined $334 million so far this month, the most since October 2012, according to data compiled by Bloomberg. Shares outstanding of the funds, including the United States Oil Fund and ProShares Ultra Bloomberg Crude Oil, rose to 55 million yesterday, a nine-month high. 

This is not an investment site. Do not make any investment, financial, or relationship decisions based on anything you read here or think you may have read here. 

 

Original Post

A long time ago I said it was taking a 100-unit train of fracking sand to frack one well. It's nice to see someone confirm my math. Reuters is reporting:

As fracking accelerates in North American shale fields, oilfield services providers Halliburton Co and Baker Hughes Inc are stockpiling sand to protect themselves against rising costs and are buying more railcars to transport the haul.

Halliburton, the world's largest provider of fracking services, is more than doubling its railcar fleet and capacity for sand terminals - where sand is stored and transferred to truck from rail. It had about 3,500 railcars under management as of June 30.

Baker Hughes, the world's No.3 oilfield services provider, said at the Barclays CEO Energy Power conference last month that it had "significantly" increased the number of its railcars and is buying more sand under contract, which helps buffer it against price rises.

Companies are pumping in as much as a trainload of frac sand into a single well to coax more oil and gas from shale rocks.

But the shale rush, especially in Texas and North Dakota, coupled with a rail jam that began after last year's severe winter has resulted in shortage of sand at drilling sites.

For newbies, my thoughts which I sent to Don, after reading the above article:

It certainly doesn't look like folks are leaving the Bakken despite slumping oil prices.

In the Bakken, EOG was the first to go from 1 million lbs of proppant to 10 million and even 12 - 14 million lbs of proppant to frack a well.

BEXP/Statoil started with and has pretty much stayed with 4 million lbs.

Most recently CLR has said that "large volume proppant" is the answer. CLR has generally gone with 1 - 4 million lbs. If CLR goes with 10 million lbs per well, one can see why so much sand is going to be needed.

Again, these are my thoughts, my opinions, what I thought I saw based on file reports and corporate presentations. They may be completely wrong. If this information is important to you, go to the source. 

I sometimes use "sand" colloquially to refer to "proppant," which could be sand alone, ceramic alone, or some combination of both. I am unaware of anything other than sand and man-made ceramic being used as proppant (there are other components mixed with sand/ceramic; whether or not others consider that "proppant," I don't know. For me proppant is sand/ceramic.

Ceramics

This post is not ready for prime time. It has not been edited (much). It has not been formatted (well). It may be way too early to post this article, but in keeping with the spirit of the mission statement of the blog (see "Wecome") I will post it:

This is an incredible article Mike Filloon has posted at SeekingAlpha. Mike is providing, incredibly, an amazing amount of analysis that many folks would charge "huge bucks" to provide.

I have not read the article ll the way through, and when I do, I will need to re-read it at least twice more.

This is a key paragraph:

The most pressing issue I have begun to see in horizontal applications within the United States are a switching to all sand fracs. From 2006 to 2008, operators had started using ceramic proppant leaseholds targeting formation deeper than 8000 feet. Due to the expense, many decided to use a mix of sand and ceramic proppant. In 2010 and 2011, wells were using sixty to seventy percent sand and the remainder in ceramic proppant. Newer frac technologies are beginning to stimulate the source rock with shorter, wider fractures. It was initially thought a well would perform better with long thin fracs. The idea was to reach as deep into the formation as possible trying to connect with natural fracturing increasing the flow of overall resource. The shorter, wider fractures have brought about a different mix of proppant. EOG Resources was the first to successfully use this tech. By focusing the hydraulic horsepower closer to the well bore, the shale is pulverized. Greater surface area is fracced, and in turn needs larger volumes of proppant. More importantly, these wells use no ceramic proppant.

Here are just a few of the story lines:

1. Mike Filloon seems somewhat surprised by this switch to all sand. He may or may not be surprised; it does not matter. I am surprised, and I would bet that half the industry is surprised.

2. Mike was one of the first, outside the industry, to note that EOG  was going all out with huge amounts of proppant and water -- much more than ever previously used -- but Mike did not say much about whether all sand, half-half, or all ceramics was the best.

3. I don't know if readers recall, but when QEP bought HELIS, QEP said it was going to go to ALL-SAND fracks. I don't know if they did. At that time, there were a lot of articles discussing sand vs ceramics. Regular readers will remember all that. I did not follow up on QEP to see if they stuck to their word, about using all sand.  Somewhere at the link below, there might be more of the discussion (I will continue to look for the exact post that mentioned QEP and all-sand -- it was in a earnings transcript by QEP or a transcript in which QEP talked about their Helis acquisition).

http://themilliondollarway.blogspot.com/2012/08/what-you-will-be-discussing-friday.html

4. Now, with regard to investing in Carbo Ceramics, this article would make me nervous. If it turns out that new methods work, and sand is just as good (or better) than ceramics, that's a huge, huge story. Disclaimer: this is not an investment site. Do not make any investment decisions based on anything you read here or what you think you might have read here.

5. The best story line, of course, is this: the operators are not sitting around, resting on their laurels. They continue to experiment, looking for the best method to complete a well. They have come a long way in the drilling aspect: reaching total depth in less than 20 days (when the Bakken started, 60 days); pad drilling, which saves all kinds of time; bigger, more powerful rigs; and, they will continue to work on the drilling.

But it's the completion technique, fracking, that will get most of their attention right now.

This was a very, very good article.

Proppant Potential In North Dakota

Link provided by Kent. Prairie Magazine reported back in November, 2012:

The North Dakota State Geological Survey recently completed a mapping project to investigate the potential for clay deposits located in the southwestern part of the state to be mined for the production of ceramic beads used as a proppant in hydraulic fracturing activities. Ceramic proppant is one of two types of proppants currently used in hydraulic fracturing activities in the Bakken region.

State geologist Ed Murphy collected approximately 200 rock samples from 61 sites in two kaolinite-rich geologic formations stretching across an area that includes the cities of Dickinson and Bowman. Collected samples were then analyzed for aluminum oxide content, which is a desired component for proppant material. According to Murphy, clay containing at least 20 percent alumina has the potential for use as a proppant. A small number of initial samples displayed an aluminum oxide content ranging from 26 to 38 percent. The larger sample pool showed to contain lower percentages of aluminum oxide, but Murphy believes the content could still be high enough to be useful. The state’s mapping project will serve to assist interested parties in further exploring the potential resource. “We’ve laid the groundwork for a company to come in and do a more detailed investigation,” he says. “Ultimately, they will need to do some small-scale mining and run that clay back into their plants” to see if it works.

It's possible this has been posted before (I don't remember) but it's relevant, again, in light of Minnesota's plan to consider a moratorium on mining fracking sand.

Still Looking For Another Proppant Source Closer to Home

Link here to mywesttexas.com.

Today's ceramic proppants come either from overseas -- Brazil, Russia or China -- or from the "kaolin belt" in Georgia and eastern Alabama. That is because they must contain either kaolin or bauxite to work in current formulations.

Austin-based Brownwood Clay Holdings, LLC, (BCH) is announcing the development of a method for making ceramic proppant out of a type of clay found near many of the top shale formations which, if proven commercially viable, could slash the cost and the delivery time for this type of proppant.

The product is currently completing the testing phase, according to Gary Davis, co-operating manager of BCH, and is looking for a partner to manufacture the proppant. Should they find one in 2013, Davis said they could have product ready for delivery by 2015.

The idea has been under consideration for two to three years, starting with the consideration of how to utilize a clay deposit on 476 acres of land BCH owned near Brownwood. BCH consists of a number of owners of this land, some of which have been connected with the property for more than 50 years, others for just a few years. The clay had previously been used for brick and tile, but Davis and his associates were looking for greater uses.

Along with that link, Don sent me a great link to a NDGS article on North Dakota clay. This is a PDF file with great photos. I remember playing on this stuff growing up in North Dakota.

And, y'all knew what video was going to show up:
The Night The Lights Went Out in Georgia, Reba McEntire

Follow-Up To That Question on Black Cat

A reader who still works in Williston, and at one time was in the ceramics distribution system in the oil patch, provided the following:

Black cat is a 100% based Chinese product, or at least it was 12 months ago.

Black Cat is not a manufacturer; they are a trader. They purchase from a supplier and have the product labeled as their own.

One can divide ceramics into two basic sources: domestic and foreign.

The domestic ceramic is a lightweight-only product and it typically produced in Georgia (southeastern United States); CARBO Ceramics has a large manufacturing facility in Georgia. Their ceramic is made with kaolin. CARBO Ceramics has manufacturing facilities in the US, China, and Russia. [I think I had a long post on CARBO Ceramics at one time; how it started out in the US, moved operations to Russia years ago.]

The foreign-made ceramic is an intermediate strength (ISP) or high strength (HSP), which are bauxite-based products.

Intermediate strength and high strength ceramics cannot be made with kaolin, but lightweight ceramics can be made with bauxite. [Australia was the leading producer of bauxite in 2010, followed by China. Interestingly enough, rock rich in kaolin is also known as China clay.]

Six months ago, the standard price was 38 cents/pound for ceramic.

The range of ceramics used per well varied from a minimum of 100,000 pounds to as much as 3 million pounds.

As a side note, it was pointed out that a cubic foot of wheat typically weighs 48 - 52 pounds; a cubic foot of 20/40 ISP typically weighs about 110 pounds.