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:

CLR Completion Strategies In The Bakken -- December 1, 2017

Updates

December 1, 2017: from comments below, from a reader --  

The operators are routinely tight lipped about the details of completion practices, but info from third parties can often be pieced together to get a sense of what is going on.

The recent introduction of Microproppants seems to be opening up vastly more area of the rock - Stimulated Reservoir Volume (SRV) is the often used term - that is able to be propped.

Some engineers claim the increase in area can be tenfold from earlier fracturing.
In addition, both the near wellbore and far field diversion products have enabled WAY more complete rubbilization of the rock and to effectively control its spread both vertically and laterally. 

Original Post  
Based on two recently fracked DUCs, it appears that CLR is keeping number of stages in a moderate range (about 40) but significantly increasing the amount of proppant, using more of the latter in the middle Bakken compared to what is used in the Three Forks:

• 28998, 1,880, CLR, Radermecher 4-22H2, Camel Butte, 39 stages; 11 million lbs, t2/17; cum 244K 10/17;
• 28991, 2,120, CLR, Radermecher 2-22H1, Camel Butte, 39 stages; 17 million lbs, t2/17; cum 270K 10/17;

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.