This large, propped
`fracture is a sight
`rarely seen. Source:
`Hydraulic Fracturing
`Research Site 1.
`
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`
`ning to deliver the delayed reports of
`what it learned from the $25-million
`research project. Federal funding for
`the project requires the partnership to
`ultimately disclose its results, with data
`releases beginning later this year. The lag
`time rewards companies that supported
`the project with a long first look.
`
`Cause and Effect?
`The completion engineers in the room
`those two mornings likely left want-
`ing more. With one exception, the
`talks avoided mentions of the ultimate
`measure of what works—production.
`Instead, they challenged widely held
`mental images of fracturing.
`For one, fracture height is overrated.
`While microseismic testing indicated
`that fractures grew up about a 1,000 ft,
`the height of the propped fractures—the
`fractures most likely to produce oil and
`gas—was about 30 ft.
`Proppant distribution was sporadic.
`While there were thick fractures full of
`
`A Look Into What
`Fractures Really Look Like
`Reports from the Hydraulic Frac-
`
`Stephen Rassenfoss, JPT Emerging Technology Senior Editor
`
`turing Test Site offer a glimpse
`into what hydraulic fractures
`really look like.
`The featured attraction in the 13 tech-
`nical papers presented over two morn-
`ings at the Unconventional Resourc-
`es Technology Conference (URTeC) was
`600 ft of rock fractured in late 2015 near
`wells in the upper and middle Wolfcamp.
`Those core samples spawned a mind-
`boggling array of observations about the
`rock, proppant, and natural and hydrau-
`lic fractures, and how they all interact.
`In the more than 2 years since the
`samples were gathered, the sections of
`core have been meticulously analyzed by
`teams of experts. More than 700 frac-
`tures were categorized based on wheth-
`er each one was created by nature,
`hydraulic force, or the stress of drill-
`ing the slant well. And the majority of
`the 400 stages pumped were studied
`using tracers and/or monitored using
`advanced diagnostics.
`
`The density and distribution of the
`fractures were measured as the scientists
`worked to understand how natural and
`hydraulic fractures interact. The bits of
`sand, calcite, and drilling mud found in
`and around the rock were collected and
`sorted. Automated imaging and pains-
`taking manual examinations were used
`to measure the size, shape, and translu-
`cence of each grain in order to identify
`and quantify the grains.
`The “incredible complexity” observed
`was “far beyond what current simula-
`tions can model and predict,” said Jor-
`dan Ciezobka, manager for research and
`development for the Gas Technology
`Institute (GTI), which managed the fed-
`eral grant supporting test site 1 and is
`planning Hydraulic Fracturing Test Site 2
`(URTeC 2937168).
`Ciezobka predicted that findings from
`the first Permian test site hosted by Lar-
`edo Petroleum in the Midland Basin
`would be studied for years to come. The
`public-private partnership is just begin-
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`used sharp variations in the pumping
`rate to increase production. “The rapid
`changes in the fluid flow, or a rate pulse,
`temporarily produce a pressure pulse of
`hundreds of thousands of pounds per
`square inch.”
`A well fractured using the variable rate
`method delivered 20% gains on average
`over four other wells on the pad where
`a steady pump pressure was used, said
`Ciezobka, who is listed as the co-inventor
`on a patent held by GTI.
`The variable rate well “clearly outper-
`formed four adjacent wells with the same
`or higher proppant loading, in both ini-
`tial production rate and cumulative pro-
`duction after 24 months,” according to
`the paper.
`Meanwhile, on the URTeC exhibit floor,
`there was a booth promoting Hydrau-
`lic Fracture Test Site 2, which is being
`hosted by Shell and Anadarko Petro-
`leum. Work will begin later this year on
`Anadarko acreage in the Delaware Basin.
`The reservoir there is significantly dif-
`ferent from the Midland Basin, home
`of Test Site 1. Results from the first site
`“will establish the foundation for investi-
`gating EOR techniques, which we plan to
`investigate” in the second site, Ciezobka
`said. This second phase of the Delaware
`Basin project will inject natural gas into
`the wells in hopes of recovering an added
`2–4% of the oil in place, according to the
`test site webpage.
`
`Proppant Packed or Not
`Large fractures packed full of sand do
`exist. In the cored rock from the fractur-
`ing test site there were fractures from
`0.5–1 cm thick full of proppant. They
`were fine examples of the large breaks in
`the rock propped open with sand.
`
`Scientists examining the rock found places where natural and hydraulic
`fractures intersected. Source: URTeC 2937168.
`
`sand inside, a paper describing fractur-
`ing (URTeC 2902624) said that only three
`of them were found among hundreds of
`propped fractures. And all of those were
`found in the upper Wolfcamp.
`While the fractured lateral in the mid-
`dle Wolfcamp was further from the slant
`well—135 ft vs. 90 ft from the nearest
`stage—the middle Wolfcamp core has a
`lot more proppant than the upper Wolf-
`camp core (URTeC 2902364).
`The sand grains collected tended to
`be extremely fine, many one-half to one-
`third the size of the grains that would just
`fit through a 100-mesh screen. Samples
`from the core tended to be mostly made
`up of those tiny particles. The three prop-
`pant packs were the exception, with a lot
`of bigger grains.
`While crushing could turn large grains
`of sand into small ones, close examina-
`tion showed that the tiny bits of sand
`
`were generally smooth and rounded,
`not the jagged shapes created by crush-
`ing. Nor did researchers find particles
`embedded in the fracture faces.
`Fractures expose many different faces.
`Some are smooth, others rough. They
`did not appear to be the simple frac-
`tures growing out in opposite directions,
`known as bi-wings, which are wide-
`ly assumed in modeling. After looking
`at hundreds of examples, Julia Gale, a
`senior research scientist for the Bureau
`of Economic Geology at the University of
`Texas at Austin, said, “we are not dealing
`with planar bi-wing things.”
`
`Payoff for Pulsations
`The papers also suggested the industry
`consider pumping jobs differently. In his
`paper, Ciezobka offered some production
`results of the sessions in a short report
`on a test of a fracturing method that
`
`At the heart of the Hydraulic Fracturing Test Site was a test well (6TW) used to collect about 450 ft of fractured rock
`from near an upper Wolfcamp well (6U) and 150 ft of core from a middle Wolfcamp well (6M). Proppant tracer was
`pumped while the three highlighted wells were fractured. Source: URTeC 2902960.
`
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`
`
`
`
`
`
`
`(a)
`
`
`
`
`
`
`
` (b)
`
`
`
`
`
` (c)
`
`
`
` 
`
`(d)
`
`(e)
`
`(f)
`
`These six cores collected from a well drilled into fractured rock shows they vary from rough to smooth. The breaks in
`some (a, b, c, d) contained drilling mud inside. Sample c, which had no sand inside, was 3.3 ft below a fracture with a
`thick proppant pack. Sample f shows a carbonate layer. Source: URTeC 2902624.
`
`In 600 ft of core, researchers found
`three big fractures packed with sand
`among hundreds of propped fractures,
`most of which were smaller. The breaks
`examined held from 1.3 pounds of par-
`ticles to a fraction of an ounce of sand,
`drilling mud, and bits of calcite and
`pyrite from the formation, said Deboty-
`am Maity, a senior engineer at GTI,
`whose presentation covered the analy-
`sis of the sludge of sand and other parti-
`cles found around the depressurized core
`(URTeC 2902364).
`What they observed resisted orderly
`categorization. Maity’s paper also noted
`that “the proppant seems to show sud-
`den jumps and drops with some core
`samples showing no proppant and
`some showing a lot.” Differences were
`ascribed to “geology/fracture or stress-
`related variations.” Hydraulic fractur-
`
`ing interacted with natural fractures in
`many ways.
`“They are certainly reactivating natural
`fractures” and there is proppant down in
`there, said Sara Elliott, a research scien-
`tist associate from the Bureau of Economic
`Geology for the University of Texas. The
`paper (URTeC 2902629) covered the pain-
`staking job of extracting and measuring
`particles found in fractures. To begin with,
`researchers had to develop a method to
`allow them to get all of the material, includ-
`ing particles that escaped the depressur-
`ized core, and then clean it, sort it, and
`record where samples were collected.
`It was “one of first attempts at physical
`collecting and quantifying injected prop-
`pant from a parted fracture break from a
`stimulated reservoir,” said Elliott.
`The total volume of proppant found
`in middle Wolfcamp fractures was a
`
`lot higher than in the upper Wolfcamp,
`where researchers observed five times
`more fractures including natural frac-
`tures. “The upper Wolfcamp hydraulic
`fracture should show a lot more inter-
`action with natural fractures, providing
`more opportunities for the proppant to
`screen out locally due to a reduction of
`fluid momentum/carrying capacity of the
`fracturing fluid,” Maity wrote.
`Other concentrations of proppant
`were found at fractures in seams between
`layers of rock with contrasting proper-
`ties. “We find that almost all of the high-
`proppant-concentration zones appear
`close to carbonate bed boundaries or
`where there is a significant change in
`stress/brittleness,” Maity said. These
`included complex fractures at the inter-
`section of beds of carbonate with con-
`trasting rock properties.
`
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`that complex fracture networks have
`on well performance,” according to a
`paper on using fracturing data for better
`modeling presented by Whitney Camp-
`bell, a geologist at Laredo Petroleum
`(URTeC 2934611).
`Analysis of hundreds of fractures was
`used to narrow down a long list of test
`methods to the ones most likely to accu-
`rately predict changes in fracture density.
`Fractured shale samples present an
`obvious challenge—the most interesting
`features are likely to crumble.
`Teams of experts brought in to mea-
`sure the size and origins of hundreds of
`these breaks had to figure out how to
`preserve these rare samples gathered at
`great cost. CT scans were done to record
`the rock in its original condition. Then it
`was placed in aluminum tubes that had
`been milled in half, forming a clamshell
`core barrel.
`Epoxy was used to stabilize a short
`section of core. That idea was quickly
`dropped because the glue changed the
`dimensions of the thin fractures and
`interfered with their opening, said Julia
`Gale, a senior research scientist for the
`Bureau of Economic Geology at the Uni-
`versity of Texas at Austin (BEG).
`Despite the core’s frail appearance,
`Gale said it “was much more intact than
`I thought and pieces were bounded by
`fractures that were mostly meaningful.”
`Gale led one of two teams—one from
`the BEG and the other led by Conoco-
`Phillips—that developed methods for
`classifying the origins of each fracture.
`Their judgment had to reflect interac-
`tions, such as hydraulic pressure inter-
`secting with natural fractures and break-
`ing open fractures long cemented shut
`by calcite.
`Like art critics asked to judge if a mas-
`ter actually painted a picture, research-
`ers assigned various degrees of certainty
`to their assessments. “We see only a small
`snapshot of each fracture,” Gale said.
`Armed with real-world data on the
`number of fractures per foot and more
`
`Imagine Fracture Modeling
`Based on Actual Fractures
`
`Depending on one’s perspective, the
`
`600 ft of core is either a really big
`sample, or not really significant.
`It is huge considering how rarely any-
`one goes to the expense of mining back
`fractured rock from a well drilled nearby.
`It is also the first reported in the Permian
`Basin. The only technical paper report-
`ing on fractured rock that was mined
`back in a liquids-rich basin was written
`by ConocoPhillips in the Eagle Ford in
`2014 (URTeC 2670034).
`But that 4-in. diameter angled well in
`the middle of an 11-well pad amounted
`to a pin prick in a formation prone to
`abrupt, unexpected changes that affect
`fracturing. Jordan Ciezobka, manager of
`research and development at the Gas
`Technology Institute, pointed out the
`
`formation is “under-sampled.” The insti-
`tute managed the federal grant support-
`ing test site 1 and is planning Hydraulic
`Fracturing Test Site 2 (URTeC 2937168).
`For those doing modeling, the data
`present a quandary. They offer physical
`evidence of what fracturing looks like in
`the ground. But the range of observations
`in the upper and middle Wolfcamp sug-
`gest the same fracturing design will per-
`form differently in a zone 325 ft deeper.
`Instead, Laredo Petroleum used
`the test results to identify what wide-
`ly available formation evaluation meth-
`ods can be used to reliably predict crit-
`ical variables, such as the presence of
`natural fractures.
`That information “is essential for
`understanding the economic impact
`
`Sand pack pushed
`out of fracture
`
`Concretion
`
`(a)
`
`Fractured shale samples present an obvious challenge—the most interesting
`features are likely to crumble. Source: URTeC 2902624.
`
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`than 30 inputs on the reservoir rock,
`Campbell said the company created a
`“facture intensity log” to reliably answer
`the question “do we see a fracture at this
`interval or not?”
`The paper described a two-stage proj-
`ect. First it narrowed the list of markers
`for predicting natural fracture intensi-
`ty to the ones most likely to get it right.
`Then they used that result as an input
`along with the best set of markers to pre-
`dict hydraulic fracturing results.
`While natural fracture data from seismic
`testing are often used, the paper questions
`the “over-reliance on seismic attributes
`that are commonly influenced by noise.”
`At the top of the list of the best predic-
`tors of natural fractures are gamma ray
`logs, shallow resistivity, and bulk density
`measures, plus a measure of brittleness,
`which Campbell said was based on an
`output from their logging software.
`Most significant on the hydraulic frac-
`ture inputs list was the gamma ray log,
`followed by Young’s modulus, shallow
`resistivity, and a model used to identify
`weak interfaces between rock layers with
`
`A cross section of a core with multiple fractures. Source: URTeC 2902624.
`
`differing properties. They help “identify
`the rock type, brittleness, stress, and the
`presence of weak interfaces.”
`The paper said the “results imply that
`hydraulic fractures have increased inten-
`sity in organic-rich shale sequences.”
`A significant input in the hydraulic
`fracturing model is an output from the
`natural fracture model used to indicate
`where fractures are prevalent. Campbell
`said that is significant because “there
`
`seems to be an inverse relation between
`natural and hydraulic fractures.”
`The work described in the paper is
`now being used to create what Campbell
`described as a “high-confidence vari-
`able” for reservoir modeling for other
`Laredo developments in the Permian.
`When asked if this has improved pro-
`duction, she said the company is “work-
`ing closely with some of our engineering
`groups to get a handle on that.”
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`Fracturing Wells in Pairs
`Creates Strong Links
`
`The 11 wells at the Hydraulic Frac-
`
`turing Test Site were fractured in
`2015 using what was then a fairly new
`method, zipper fracturing. Rather than
`pumping one well at a time, wells were
`fractured in groups—four pairs, plus
`three wells together in the middle of
`the pattern.
`Zipper fracturing speeds work by
`allowing continuous pumping and it
`reduces the risk of frac hits because the
`method only fractures rock where pres-
`sure has not been depleted by produc-
`tion. Now zipper fracturing is used to
`fracture even more wells at once.
`What researchers found at the frac-
`turing test site was that zipper frac-
`tures create strong connections. By
`tracking the pressure responses in
`nearby wells during fracturing, and the
`chemical tracers in the fluids pumped
`during fracturing, they measured the
`higher degree of connection among
`those wells.
`While fluids injected during fractur-
`ing were later observed at other wells
`on the pad, the ones that were zipper
`fractured showed more communication,
`said Ashish Kumar, a graduate research
`assistant in petroleum engineering at
`the University of Texas at Austin, who
`presented a paper on tracer and pres-
`sure data analysis at the recent Uncon-
`ventional Resources Technology Con-
`ference (URTeC 2901827).
`Connections matter because they can
`provide a pathway for well interference.
`The strongest connections were wells in
`which proppant tracers traveled from
`well to well, suggesting the passage-
`way has been propped open. The paper
`said that “proppant exchange is very
`likely to happen between zipper frac-
`tured wells.”
`Simultaneous fracturing is likely to
`create stronger connections because
`
`the time between stages is relatively
`short, allowing fluid pumped in one
`stage to stimulate “induced un-propped
`fractures that have not closed over this
`short time” from the previous stage,
`he said.
`Most of the well pairs were on the
`same bench, spaced 660 ft apart. The
`five lower wells were 325 ft deeper and
`spaced in between the six upper wells.
`Fractures connected end-to-end can
`run 1,000 ft or more, but they gener-
`ally do not have a lasting impact unless
`the pathway was propped—radioactive
`tracer tests showed some propped con-
`nections among well pairs.
`Connected fractures without prop-
`pant closed after production began, as
`did all connections between the middle
`and upper Wolfcamp. Pumping more
`sand increased the probability of inter-
`action among multiple wells.
`A related study by Core Laboratories
`found that the same fracturing treat-
`ment performed differently in differ-
`ent benches. “Interwell communication
`within the middle Wolfcamp wells was
`significantly higher than communica-
`tion within the upper Wolfcamp wells,”
`according to a technical paper by the
`company (URTeC 2902960).
`It also reported that a high percentage
`of proppant had traveled into the reser-
`voir. The proppant was treated to give
`off a low-level radioactive signal, and
`the paper concluded more than 90% of
`the clusters were treated. The signal was
`detected using a gamma ray log whose
`range is limited to an area within a cou-
`ple feet of the wellbore.
`The paper reported that proppant
`injected at clusters 50 ft apart were as
`effective as those spaced 90 ft apart, and
`the wider spacing left more rock unstim-
`ulated. This did not vary between wells
`in the upper and middle Wolfcamp. JPT
`
`For Further Reading
`
`URTeC 2937168 Hydraulic
`Fracturing Test Site (HFTS)—
`Project Overview and Summary
`of Results by Jordan Ciezobka,
`Gas Technology Institute; James
`Courtier, and Joe Wicker, Laredo
`Petroleum.
`URTeC 2902624 Hydraulic
`Fractures in Core From
`Stimulated Reservoirs: Core
`Fracture Description of HFTS
`Slant Core, Midland Basin,
`West Texas by Julia F. W. Gale,
`Sara J. Elliott, and Stephen E.
`Laubach, University of Texas
`at Austin.
`URTeC 2902364 Assessment of
`In-Situ Proppant Placement in
`SRV Using Through-Fracture
`Core Sampling at HFTS by
`Debotyam Maity, Jordan
`Ciezobka, and Sarah Eisenlord,
`Gas Technology Institute.
`URTeC 2902629 Analysis and
`Distribution of Proppant
`Recovered from Fracture Faces
`in the HFTS Slant Core Drilled
`Through a Stimulated Reservoir
`by Sara J. Elliott and Julia F.W.
`Gale, University of Texas at
`Austin.
`URTeC 2934611 Natural and
`Hydraulic Fracture Density
`Prediction and Identification
`of Controllers by Whitney
`Campbell, Joe Wicker, and James
`Courtier, Laredo Petroleum.
`URTeC 2901827 Well Interference
`Diagnosis Through Integrated
`Analysis of Tracer and Pressure
`Interference Tests by Ashish
`Kumar, Puneet Seth, and
`Kaustubh Shrivastava, et al.,
`University of Texas at Austin.
`URTeC 2902960 Interwell
`Communication Study of UWC
`and MWC Wells in the HFTS
`by Tanner Wood, Richard
`Leonard, and Chad Senters, et
`al., ProTechnics Division of Core
`Laboratories.
`
`36
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