H Y D R A U L I C
`
`History of
`
`A N E N D U R I N G T E C H N O L O G Y
`
`Carl T. Montgomery and Michael B. Smith, NSI Technologies
`
`Editor’s note: In 2006, SPE honored nine pioneers of the hydraulic fracturing industry as Legends of
`Hydraulic Fracturing. Claude E. Cooke Jr., Francis E. Dollarhide, Jacques L. Elbel, C. Robert Fast, Robert
`R. Hannah, Larry J. Harrington, Thomas K. Perkins, Mike Prats, and H.K. van Poollen were recognized as
`instrumental in developing new technologies and contributing to the advancement of the fi eld through their
`roles as researchers, consultants, instructors, and authors of ground-breaking journal articles.
`
`Following is an excerpt from SPE’s new Legends of Hydraulic Fracturing CDROM, which contains an
`extended overview of the history of the technology, list of more than 150 technical papers published by
`these industry legends, personal refl ections from a number of the Legends and their colleagues, and historic
`photographs. For more information on the CDROM, please go to http://store.spe.org/Legendsof-Hydraulic-
`Fracturing-P433.aspx.
`
`
`
`2626
`
`JPT • DECEMBER 2010
`JPT • DECEMBER 2010
`
`IWS EXHIBIT 1042
`
`EX_1042_001
`
`

`

`S
`
`ince Stanolind Oil
`introduced hydraulic
`fracturing in 1949, close
`to 2.5 million fracture
`treatments have been performed
`worldwide. Some believe that
`approximately 60% of all wells
`drilled today are fractured. Fracture
`stimulation not only increases the
`production rate, but it is credited
`with adding to reserves—9 billion
`bbl of oil and more than 700 Tscf of
`gas added since 1949 to US reserves
`alone—which otherwise would have
`been uneconomical to develop.
`In addition, through accelerating
`production, net present value of
`reserves has increased.
`Fracturing can be traced to
`the 1860s, when liquid (and later,
`solidifi ed) nitroglycerin (NG) was
`used to stimulate shallow, hard
`rock wells in Pennsylvania, New
`York, Kentucky, and West Virginia.
`Although extremely hazardous,
`and often used illegally, NG was
`spectacularly successful for oil well
`“shooting.” The object of shooting a
`well was to break up, or rubblize,
`the oil-bearing formation to increase
`both initial fl ow and ultimate
`recovery of oil. This same fracturing
`principle was soon applied with equal
`effectiveness to water and gas wells.
`In the 1930s, the idea of injecting
`a nonexplosive fl uid (acid) into the
`ground to stimulate a well began
`to be tried. The “pressure parting”
`phenomenon was recognized in
`well-acidizing operations as a means
`
`Fig. 1—In 1947, Stanolind Oil conducted
`the fi rst experimental fracturing in the
`Hugoton fi eld located in southwestern
`Kansas. The treatment utilized napalm
`(gelled gasoline) and sand from the
`Arkansas River.
`
`Fig. 2—On 17 March, 1949, Halliburton conducted the fi rst two commercial fracturing
`treatments in Stephens County, Oklahoma, and Archer County, Texas.
`
`of creating a fracture that would not
`close completely because of acid
`etching. This would leave a fl ow
`channel to the well and enhance
`productivity. The phenomenon
`was confi rmed in the fi eld, not
`only with acid treatments, but also
`during water injection and squeeze-
`cementing operations.
`But it was not until Floyd Farris
`of Stanolind Oil and Gas Corporation
`(Amoco) performed an in-depth
`study to establish a relationship
`between observed well performance
`and treatment pressures that
`“formation breakdown” during
`acidizing, water injection, and
`squeeze cementing became better
`understood. From this work, Farris
`conceived the idea of hydraulically
`fracturing a formation to enhance
`production from oil and gas wells.
`The fi rst experimental treatment
`to “Hydrafrac” a well for stimulation
`was performed in the Hugoton gas
`fi eld in Grant County, Kansas, in
`1947 by Stanolind Oil (Fig. 1). A
`total of 1,000 gal of naphthenic-acid-
`and-palm-oil- (napalm-) thickened
`gasoline was injected, followed by
`a gel breaker, to stimulate a gas-
`producing limestone formation at
`2,400 ft. Deliverability of the well did
`not change appreciably, but it was a
`start. In 1948, the Hydrafrac process
`was introduced more widely to the
`
`industry in a paper written by J.B.
`Clark of Stanolind Oil. A patent was
`issued in 1949, with an exclusive
`license granted to the Halliburton Oil
`Well Cementing Company (Howco)
`to pump the new Hydrafrac process.
`Howco performed the fi rst two
`commercial fracturing treatments—
`one, costing USD 900, in Stephens
`County, Oklahoma, and the other,
`costing USD 1,000, in Archer
`County, Texas—on March 17, 1949,
`using lease crude oil or a blend of
`crude and gasoline, and 100 to 150
`lbm of sand (Fig. 2). In the fi rst
`year, 332 wells were treated, with
`an average production increase of
`75%. Applications of the fracturing
`process grew rapidly and increased
`the supply of oil in the United States
`far beyond anything anticipated.
`Treatments reached more than 3,000
`wells a month for stretches during
`the mid-1950s. The fi rst one-half-
`million-pound fracturing job in the
`free world was performed in October
`1968, by Pan American Petroleum
`Corporation (later Amoco, now BP)
`in Stephens County, Oklahoma. In
`2008, more than 50,000 frac stages
`were completed worldwide at a
`cost of anywhere between USD
`10,000 and USD 6 million. It is now
`common to have from eight to as
`many as 40 frac stages in a single
`well. Some estimate that hydraulic
`
`
`
`H Y D R A U L I C F R A C T U R I N G T H E F U S S , T H E F A C T S , T H E F U T U R EH Y D R A U L I C F R A C T U R I N G T H E F U S S , T H E F A C T S , T H E F U T U R E
`
`27
`27
`
`IWS EXHIBIT 1042
`
`EX_1042_002
`
`

`

`essential parallel development
`meant fewer pounds of gelling
`agent were required to obtain a
`desired viscosity. As more and
`more fracturing treatments have
`involved high-temperature wells,
`gel stabilizers have been developed,
`the fi rst of which was the use
`of approximately 5% methanol.
`Later, chemical stabilizers were
`developed that could be used alone
`or with the methanol.
`Improvements in crosslinkers
`and gelling agents have resulted
`in systems that permit the fl uid
`to reach the bottom of the hole in
`high-temperature wells prior to
`crosslinking, thus minimizing the
`effects of high shear in the tubing.
`Ultraclean gelling agents based on
`surfactant-association chemistry and
`encapsulated breaker systems that
`activate when the fracture closes
`have been developed to minimize
`fracture-conductivity damage.
`
`Proppants
`The fi rst fracturing treatment
`used screened river sand as a
`proppant. Others that followed
`used construction sand sieved
`through a window screen. There
`have been a number of trends
`in sand size, from very large to
`small, but, from the beginning, a
`–20 +40 US-standard-mesh sand
`has been the most popular, and
`currently approximately 85% of the
`sand used is this size. Numerous
`propping agents have been evaluated
`throughout the years, including
`plastic pellets, steel shot, Indian
`glass beads, aluminum pellets, high-
`strength glass beads, rounded nut
`shells, resin-coated sands, sintered
`bauxite, and fused zirconium.
`The concentration of sand
`(lbm/fl uid gal) remained low until the
`mid-1960s, when viscous fl uids such
`as crosslinked water-based gel and
`viscous refi ned oil were introduced.
`Large-size propping agents were
`advocated then.
`The trend then changed from
`the monolayer or partial monolayer
`concept to pumping higher sand
`concentrations. Since that time, the
`
`JPT • DECEMBER 2010
`
`Fig. 3—A 1955 frac pump manufacturing facility. These remotely controlled pumps were
`powered by 1,475 hp surplus Allison aircraft engines used during World War II.
`
`fracturing has increased US
`recoverable reserves of oil by at least
`30% and of gas by 90%.
`
`Fluids and Proppants
`Soon after the fi rst few jobs, the
`average fracture treatment consisted
`of approximately 750 gal of fl uid and
`400 lbm of sand. Today treatments
`average approximately 60,000 gal of
`fl uid and 100,000 lbm of propping
`agent, with the largest treatments
`exceeding 1 million gal of fl uid and
`5 million lbm of proppant.
`
`Fluids
`The fi rst fracture treatments were
`performed with a gelled crude. Later,
`gelled kerosene was used. By the
`latter part of 1952, a large portion of
`fracturing treatments were performed
`with refi ned and crude oils. These
`fl uids were inexpensive, permitting
`greater volumes at lower cost. Their
`lower viscosities exhibited less
`friction than the original viscous
`gel. Thus, injection rates could be
`obtained at lower treating pressures.
`To transport the sand, however,
`higher rates were necessary to offset
`the fl uid’s lower viscosity.
`With the advent in 1953 of water
`as a fracturing fl uid, a number of
`gelling agents were developed. The
`
`28
`
`fi rst patent (US Patent 3058909)
`on guar crosslinked by borate was
`issued to Loyd Kern with Arco
`on October 16, 1962. One of the
`legends of hydraulic fracturing, Tom
`Perkins, was granted the fi rst patent
`(US Patent 3163219) on December
`29, 1964 on a borate gel breaker.
`Surfactants were added to minimize
`emulsions with the formation fl uid,
`and potassium chloride was added
`to minimize the effect on clays and
`other water-sensitive formation
`constituents. Later, other clay-
`stabilizing agents were developed
`that enhanced the potassium
`chloride, permitting the use of water
`in a greater number of formations.
`Other innovations, such as foams
`and the addition of alcohol, have also
`enhanced the use of water in more
`formations. Aqueous fl uids such as
`acid, water, and brines are used now
`as the base fl uid in approximately
`96% of all fracturing treatments
`employing a propping agent.
`In the early 1970s, a major
`innovation in fracturing fl uids was
`the use of metal-based crosslinking
`agents to enhance the viscosity
`of gelled water-based fracturing
`fl uids for higher-temperature wells.
`It is interesting to note that the
`chemistry used to develop these
`fl uids was “borrowed” from the
`plastic explosives industry. An
`
`IWS EXHIBIT 1042
`
`EX_1042_003
`
`

`

`One Tough
`Proppant
`
`“We knock out lightweights”
`
`New PowerProp® with MultiCoat Technology delivers
`greater strength and better performance than the leading
`lightweight ceramic proppant.
`
`We beat lightweights in every category!
`(cid:116)(cid:1)(cid:41)(cid:80)(cid:85)(cid:1)(cid:88)(cid:70)(cid:85)(cid:1)(cid:68)(cid:83)(cid:86)(cid:84)(cid:73)
`(cid:116)(cid:1)(cid:36)(cid:80)(cid:79)(cid:69)(cid:86)(cid:68)(cid:85)(cid:74)(cid:87)(cid:74)(cid:85)(cid:90)
`(cid:116)(cid:1)(cid:35)(cid:70)(cid:85)(cid:66)(cid:1)(cid:81)(cid:70)(cid:83)(cid:71)(cid:80)(cid:83)(cid:78)(cid:66)(cid:79)(cid:68)(cid:70)
`
`More strength and flexibility from our patented
`coating technology means reaching and maintaining
`higher peaks before crush.
`
`We’ll prove it at
`PowerProp.com
`1-888-SANTROL
`
`Why would you ever use a lightweight ceramic again?
`
`MultiCoat Proppant
`
`See us at SPE Hydraulic Fracturing Conference–Booth #43
`
`IWS EXHIBIT 1042
`
`EX_1042_004
`
`

`

`Courtesy Halliburton
`
`Courtesy Schlumberger
`
`Fig. 4—Early screw-type sand blender.
`
`Fig. 5—Modern fl uid/proppant blender or
`proportioning unit.
`
`concentration has increased almost
`continuously, with a sharp increase
`in recent years. These high sand
`concentrations are due largely to
`advances in pumping equipment and
`improved fracturing fl uids. Now it
`is not uncommon to use proppant
`concentrations averaging 5 to 8 lbm/
`gal throughout the treatment, with a
`low concentration at the start of the
`job, increased to 20 lbm/gal toward
`the end of the job.
`
`Pumping and
`Blending Equipment
`Hydraulic horsepower (hhp) per
`treatment has increased from an
`average of approximately 75 hhp
`to more than 1,500 hhp. There
`are cases where, with as much as
`15,000 hhp available, more than
`10,000 hhp was actually used, in
`
`stark contrast with some early
`jobs, where only 10 to 15 hhp was
`employed. Some of the early pump
`manufacturing facilities made
`remotely controlled pumps powered
`by surplus Allison aircraft engines
`used during World War II
`(Figs. 3, 6).
`Initial jobs were performed
`at rates of 2 to 3 bbl/min. This
`increased rapidly until the early
`1960s, when it rose at a slower rate,
`settling in the 20 bbl/min range
`(even though there were times
`when the rate employed in the
`Hugoton fi eld was more than 300
`bbl/min). Then in 1976, Othar Kiel
`started using high-rate “hesitation”
`fractures to cause what he called
`“dendritic” fractures. Today, in the
`unconventional shale-gas plays,
`Kiel’s ideas are used where the
`pump rates are more than 100 bbl/
`
`Fig. 6—Vintage 1950s remotely controlled frac pumper powered by surplus WWII
`Allison aircraft engines.
`
`min. Surface treating pressures
`sometimes are less than 100 psi, yet
`others may approach 20,000 psi.
`Conventional cement- and
`acid-pumping equipment was
`used initially to execute fracturing
`treatments. One to three units
`equipped with one pressure pump
`delivering 75 to 125 hhp were
`adequate for the small volumes
`injected at the low rates. Amazingly,
`many of these treatments gave
`phenomenal production increases.
`As treating volumes increased,
`accompanied by a demand for greater
`injection rates, special pumping and
`blending equipment was developed.
`Development of equipment including
`intensifi ers, slinger, and special
`manifolds continues. Today, most
`treatments require that service
`companies furnish several million
`dollars’ worth of equipment.
`For the first few years, sand
`was added to the fracturing fl uid by
`pouring it into a tank of fracturing
`fl uid over the suction. Later, with
`less-viscous fl uid, a ribbon or paddle
`type of batch blender was used.
`Shortly after this, a continuous
`proportioner blender utilizing
`a screw to lift the sand into the
`blending tub was developed (Fig. 4).
`Blending equipment has become
`very sophisticated to meet the need
`for proportioning a large number
`of dry and liquid additives, then
`uniformly blending them into the
`base fl uid and adding the various
`concentrations of sand or other
`propping agents. Fig. 5 shows one
`of these blending units.
`To handle large propping-agent
`volumes, special storage facilities
`were developed to facilitate their
`delivery at the right rate through the
`fl uid. Treatments in the past were
`conducted remotely but still without
`any shelter. Today, treatments have
`a very sophisticated control center
`to coordinate all the activities that
`occur simultaneously.
`
`Fracture-Treatment Design
`The fi rst treatments were designed
`using complex charts, nomographs,
`
`30
`
`JPT • DECEMBER 2010
`
`IWS EXHIBIT 1042
`
`EX_1042_005
`
`

`

`PKN
`(Perkins & Kern)
`
`GDK
`(Geertsma & de Klerk)
`
`hf
`
`Xf
`
`wf
`
`Area of largest
`flow resistance
`
`Approximately elliptical
`shape of fracture
`
`Xf
`
`wf
`
`Fig. 7—Early 2D fracture-geometry models.
`
`TVD
`m
`4380
`
`4400
`
`4420
`
`4440
`
`79.65 min
`
`0.000
`
`1.416
`
`2.833
`
`4.249
`
`5.666
`
`7.082
`
`8.499
`
`9.915
`
`
`
`11 33211.332
`
`12.748
`
`14.165
`0.115 m
`
`10000 11000 12000 13000
`Stress (psi)
`
`50
`
`100
`Fracture Penetration (m)
`
`150
`
`Courtesy NSI Technologie
`
`Fig. 8—Modern fully gridded frac model showing fl uid and
`proppant vectors.
`
`and calculations to determine
`appropriate size, which generally
`was close to 800 gal (or multiples
`thereof) of fl uid, with the sand at
`concentrations of 0.5 to 0.75 lbm/
`gal. This largely hit-or-miss method
`was employed until the mid-1960s,
`when programs were developed
`for use on simple computers. The
`original programs were based on
`work developed by Khristianovic
`
`and Zheltov (1955), Perkins and
`Kern (1961), and Geertsma and
`de Klerk (1969) on fl uid effi ciency
`and the shape of a fracture system
`in two dimensions (Fig. 7). These
`programs were a great improvement
`but were limited in their ability to
`predict fracture height.
`As computer capabilities
`have increased, frac-treatment-
`design programs have evolved to
`
`include fully gridded fi nite-element
`programs that predict fracture
`geometry and fl ow properties
`in three dimensions (Fig. 8).
`Today, programs are available to
`obtain a temperature profi le of the
`treating fl uid during a fracturing
`treatment, which can assist in
`designing the concentrations of
`the gel, gel-stabilizer, breaker, and
`propping-agent during treatment
`
`H Y D R A U L I C F R A C T U R I N G T H E F U S S , T H E F A C T S , T H E F U T U R E
`
`31
`
`IWS EXHIBIT 1042
`
`EX_1042_006
`
`

`

`stages. Models have been developed
`to simulate the way fl uids move
`through the fracture and the way the
`propping agent is distributed. From
`these models, production increases
`can be determined. Models can
`also be used to historically match
`production following a fracturing
`treatment to determine which
`treatment achieved which actual
`result. New capabilities are currently
`being developed that will include the
`interaction of the induced fracture
`with natural fractures.
`One of the hydraulic fracturing
`legends, H.K. van Poollen, performed
`work on an electrolytic model
`to determine the effect fracture
`lengths and fl ow capacity would
`have on the production increase
`obtained from wells with different
`drainage radii. Several others
`developed mathematical models for
`similar projections. Today, there
`are models that predict production
`from fractures with multiphase
`
`and non-Darcy fl ow using any
`proppant available.
`
`Fracturing’s Historic Success
`Many fi elds would not exist today
`without hydraulic fracturing. In the US,
`these include the Sprayberry trend in
`west Texas; Pine Island fi eld, Louisiana;
`Anadarko basin; Morrow wells,
`northwestern Oklahoma; the entire San
`Juan basin, New Mexico; the Denver
`Julesburg basin, Colorado; the east
`Texas and north Louisiana trend,
`Cotton Valley; the tight gas sands of
`south Texas and western Colorado; the
`overthrust belt of western Wyoming;
`and many producing areas in the
`northeastern US.
`As the global balance of
`supply and demand forces the
`hydrocarbon industry toward more
`unconventional resources including
`US shales such as the Barnett,
`Haynesville, Bossier, and Marcellus
`gas plays, hydraulic fracturing
`
`will continue to play a substantive
`role in unlocking otherwise
`unobtainable reserves. JPT
`
`References
`Geerstma, J. and de Klerk, F. 1969.
`A Rapid Method of Predicting
`Width and Extent of Hydraulically
`Induced Fractures. J. Pet. Tech. 21
` (12):1571–1581.
`van Poollen, H.K., Tinsley, J.M.,
`and Saunders, C.D. 1958.
`Hydraulic Fracturing—Fracture
`Flow Capacity vs. Well Productivity.
`Trans., AIME 213: 91–95. SPE-890-G.
`Hubbard and Willis (1956).
`Khristianovic, S.A. and Zheltov, Y.P.
`1955. Formation of Vertical
`Fractures by Means of Highly
`Viscous Liquid. Paper 6132 presented
`at the 4th World Petroleum Congress,
`Rome, 6–15 June.
`Perkins, T.K. and Kern, L.R. (1961).
` Widths of Hydraulic Fractures.
`J. Pet. Tech., 13 (9): 937–949. SPE-
`89-PA. DOI: 10.2118/89-PA.
`
`SPE Hydraulic Fracturing
`Technology Conference
`
`(cid:18)(cid:20)(cid:110)(cid:18)(cid:22)(cid:0)(cid:42)(cid:65)(cid:78)(cid:85)(cid:65)(cid:82)(cid:89)(cid:0)(cid:18)(cid:16)(cid:17)(cid:17)(cid:0)(cid:115)(cid:0)The Woodlands Waterway Marriott Hotel & Convention Center
`The Woodlands, Texas, USA
`
`Register Now!
`
`www.spe.org/events/hftc
`
`32
`
`JPT • DECEMBER 2010
`
`IWS EXHIBIT 1042
`
`EX_1042_007
`
`

`

`Cleaner fracs
`through
`chemistry.
`
` Introducing the
`Process and Products from Multi-Chem.
`
`Multi-Chem has developed NaturaLine™, a product line and
`product evaluation process that provides environmental
`solutions for your toughest completion challenges.
`
`The NaturaLine products – biocides, friction reducers,
`scale inhibitors and surfactants – can reduce waste
`disposal and water treatment costs, and even chemical usage
`amounts. These custom-designed products reduce toxicity
`in your frac fl uids, produced fl uids and fl owback fl uids.
`
`With the NaturaLine process, Multi-Chem works with operators
`to develop specialized, cost-effective chemical completion
`solutions to protect your well throughout its life cycle.
`
`Ever quizzed about the make-up of your chemical program?
`With Multi-Chem, the answers are easy. For the most
`effective way to select completion chemicals, visit our
`website at www.multichem.com/NaturaLine.
`
`©Copyright 2010. All rights reserved.
`
`IWS EXHIBIT 1042
`
`EX_1042_008
`
`

`

`H Y D R A U L I C
`
`T H E F U S S , T H E F A C T S , T H E F U T U R E
`
`Robin Beckwith, JPT/JPT Online Staff Writer
`
`While precise statistics on the hydraulic fracturing industry are not kept, there is little doubt its use has
`grown precipitously over the past decade. Despite low gas prices, North American fracturing activity is at
`an all-time high, with competition between fracturing companies fi erce, margins slim, and volumes huge.
`With an estimated 4 million hhp of equipment being built in the US, there are waiting lists for services
`and supplies, and delays of up to 9 months are common. China and India are investigating the potential
`of unconventional-gas resources that demand the use of hydraulic fracturing to produce at commercial
`fl ow rates, and also are stepping up investment in North American and Australian shale acreage. European
`countries like Hungary, Poland, Germany, and France—keen on easing dependence on Russian energy—are
`also looking to exploit their tight resources.
`
`34
`
`JPT • DECEMBER 2010
`
`IWS EXHIBIT 1042
`
`EX_1042_009
`
`

`

`Fig. 1—Estimated size of the global fracturing market since 1999.
`Courtesy: Michael Economides, Energy Tribune.
`
`Fig. 2—Equipped with 8,250 hhp and 15,000 psi-capable pumps
`and manifolds, Halliburton’s Stim Star Angola delivers a wide
`range of stimulation services offshore West Africa.
`Photo courtesy: Halliburton.
`
`But it is not all about shale. With
`2007 estimated service-company
`hydraulic fracturing revenues
`representing a global market of
`USD 13 billion (Fig. 1), up from
`approximately USD 2.8 billion in
`1999, the technique is now more
`than ever a vital practice enabling
`continued economic exploitation
`of hydrocarbons throughout the
`world—from high-permeability oil
`fi elds in Alaska, the North Sea, and
`Russia, to unconsolidated formations
`in the Gulf of Mexico, Santos Basin,
`and offshore West Africa (Fig. 2), to
`unconventional resources such as
`shale and coalbed methane (CBM)
`developments (Fig. 3).
`
`What Is Driving the Rise
`in Hydraulic Fracturing?
`It is not surprising to fi nd that
`North America is home to an
`estimated 85% of the total number of
`hydraulic fracturing spreads (Fig. 4)
`(according to Michael Economides,
`a spread is the equivalent of four
`fracturing units, a blender, and
`ancillary equipment)—including land
`(Fig. 5) and offshore equipment.
`This stems from its mature,
`reliable infrastructure, fueled by
`the dependence of a population
`long used to creating demand. The
`
`phenomenal increase in US proved
`reserves of natural gas—from a 20-
`year low in 1994 of 162.42 Tcf to its
`2009 estimated 244.66 Tcf—is the
`direct result of advances in hydraulic
`fracturing and horizontal drilling.
`The scramble for this resource,
`however, giving rise to what an IHS
`CERA report calls the “shale gale,”
`is the result in North America to
`avert what was predicted earlier
`in the century to be the need to
`import vast quantities of natural
`gas in the form of liquefi ed natural
`gas (LNG) from farfl ung locations.
`Although shale and CBM are also
`widely prevalent outside the US, the
`need in most countries—with the
`possible exception of the European
`Economic Union—to turn to them,
`
`remains less urgent, as conventional
`resources remain far from depleted.
`Indeed, the top three countries in
`terms of estimated proved natural-
`gas reserves—Russia, Iran, and
`Qatar—held a combined total 14.5
`times that in the US, at 3,563.55 Tcf
`year-end 2009, 57% of the world’s
`2009 total estimated proved reserves
`of 6,261.29 Tcf. So, while hydraulic
`fracturing and natural gas—and to
`a certain extent oil—extraction have
`been linked in the recent focus on
`unconventional shale resources
`within the US, the long-term future
`lies well outside that country.
`Currently within North America,
`10 or more fracture-treatment
`stages are performed to stimulate
`production along a horizontal
`
`Fig. 3—Estimate of approximate breakdown of fracture treatments by well type.
`Courtesy: Michael Economides, Energy Tribune.
`
`H Y D R A U L I C F R A C T U R I N G T H E F U S S , T H E F A C T S , T H E F U T U R E
`
`35
`
`IWS EXHIBIT 1042
`
`EX_1042_010
`
`

`

`the US has been fast—propelled in
`part by regulatory requirements
`in most areas throughout North
`America to reveal fracturing and
`production-performance data within
`6 months following execution,
`which competitors can then plunder
`for insight. The US also benefi ted
`from a tax incentive created in
`the 1980s, which, along with high
`gas prices, jump-started US tight
`gas exploitation. By 1992, when
`the incentive ended, the resulting
`infrastructure, critical mass, and
`expertise were in place to continue
`economically without incentives.
`Driven by increasing demand
`for power generation, countries
`like China and India are eager to
`cost-effectively develop their own
`resources, as well as participate
`in the boom that has struck US
`shale. In August, both nations
`signed agreements with the US
`State Department allowing the US
`Geological Survey to evaluate data
`on potential shale plays within
`those countries to determine if the
`formations possess recoverable gas.
`They are also grabbing up
`resources within the US. For
`example, India’s largest company,
`Reliance Industries, led by
`billionaire Mukesh Ambani, has
`purchased shares in US shales worth
`USD 3.4 billion so far this year.
`Ambani appears to be pursuing a
`learn-as-you-earn strategy. Evidence
`for this can be found in the nature of
`the joint venture into which Reliance
`entered with Carrigo Oil & Gas on
`Marcellus Shale acreage in central
`and northeast Pennsylvania in
`early August. Reliance holds a 60%
`interest and Carrigo is the operator,
`but Reliance has the option to act
`as operator in certain regions in the
`coming years. Ambani expects to
`build on what his company learns
`about techniques like fracturing
`while profi ting as approximately
`1,000 wells are drilled over the
`next 10 years within a net resource
`potential of about 3.4 Tcfe (2.0 Tcfe
`to Reliance).
`Smaller countries, like France
`and Norway, are pursuing similar
`
`JPT • DECEMBER 2010
`
`Fig. 4—Estimated global distribution of fracturing equipment, including land fracturing
`spreads and offshore vessels.
`
`borehole, while typically outside
`North America, the number of
`fracture-treatment stages per well
`is rarely more than two or three.
`Low natural-gas prices and lack of
`infrastructure are two key drivers
`for this phenomenon. Outside
`North America, service companies
`have yet to establish—or benefi t
`from—suffi cient infrastructure or
`gain enough experience to deliver
`consistent results.
`Costs that service companies
`must deal with per well tend to be
`three to four times higher outside
`North America due to such factors
`as fragile distribution channels or
`poorly performing equipment and
`personnel. The result is that service
`
`Fig. 5—Hydraulic fracturing treatment,
`Woodford Shale, Canadian County,
`Oklahoma, for which Halliburton provided
`52,000 hhp.
`
`36
`
`companies must charge higher
`prices to remain economically
`viable, which in turn makes it
`highly unattractive for operators to
`permit learning, through practice
`and analysis, about the formation
`and about how to run the fl eet
`and crew. However, a practical
`way to combat this, according to
`BP Exploration senior petroleum
`engineer and adviser Martin
`Rylance, is to deeply focus on the
`operational quality assurance/quality
`control and execution on the pilot
`fracture treatments, and simply
`overdesign these treatments with
`more length and conductivity than
`strictly necessary. Optimization of
`the fracture treatments can be an
`evolving story as more treatments
`are performed. The absolute key,
`said Rylance, is to fi rst establish
`effective, competent, and successful
`fracturing and economical results.
`The development and
`application of hydraulic fracturing
`technology in the US has been
`driven by independents, with a
`low cost base and the critical mass
`necessary to learn and respond
`quickly to new developments in
`modeling, planning, fl uids, and
`proppants technology. With plays
`containing dozens of operators, each
`seeking technical and economic
`advantage over the other, the pace
`of technological development in
`
`IWS EXHIBIT 1042
`
`EX_1042_011
`
`

`

`Welcome to the new age
`of reservoir stimulation.
`
`STEWARDSHIP
`
`CUSTOMER
`SERVICE
`
`OPTIMUM
`PERFORMANCE
`
`ECOENVIRONMENTAL
`
`G R E E N
`
`Yes, you can have it all. A stimulation solution that optimizes well performance, provides
`world-class customer service, AND uses revolutionary GREEN technologies to help protect the
`environment. Welcome to ECO-Green. Welcome to Frac Tech. www.fractech.net/eco-green
`
`Toll Free: 866.877.1008
`
`www.fractech.net
`
`Stage After Stage
`
`IWS EXHIBIT 1042
`
`EX_1042_012
`
`

`

`in late 2008 when it fi rst acquired
`acreage from Chesapeake, and
`aims to have shale production of
`50,000 BOEPD from these assets
`by 2012. The company intends to
`build infrastructure and confi dence
`through its Chesapeake joint
`venture to become an operator of
`unconventional-gas assets.
`Another strategy is to invite
`experienced foreign companies
`to share in exploiting home-front
`shales. For example, China’s largest
`listed gas producer, Petrochina, and
`Royal Dutch Shell have partnered
`to develop shale-gas resources
`in China’s Sichuan province.
`PetroChina, however, is hedging its
`bets: It also has planned USD 60
`billion in overseas investments to
`boost its oil and gas output, following
`the example of other companies
`like China Petroleum & Chemical
`Corporation and CNOOC.
`
`Keeping the Fracture
`Open: Proppants
`With the rapid rise in hydraulic
`fracturing over the past decade,
`the number of proppant suppliers
`worldwide has increased from
`a handful to more than 30 sand
`producers, nine resin coaters, and at
`least 10 ceramic manufacturers.
`According to a 2009 global
`proppant market study by D.
`Anschutz and B. Olmen, published
`by PropTester and Kelrik in early
`2010, proppant consumption was
`a low-growth market through the
`1990s, but rose from an estimated
`3 billion pounds in 1999 to total
`consumption of nearly 20 billion
`pounds in 2009 (Fig. 6).
`Proppant grain size has become
`fi ner as the use of slickwater
`fracturing has increased, with
`20/40 the dominant gradation
`throughout the 1990s and early
`2000s. However, according to
`Kelrik owner Olmen, “Slickwater
`fracturing of unconventional-gas
`resources represents nothing short
`of a paradigm shift in its impact
`on proppant volumes, types, and
`sizes.” The result is that today the
`
`use of 30/50 and 40/70 sand and
`resin-coated sand, 40/80 ceramics,
`and 100-mesh sands of various
`gradations is common.
`It is interesting to note, however,
`that the use of proppants 16/20 or
`larger in fractures performed in West
`Siberia, for example, has increased
`from 43% of the jobs in 2003 to more
`than 90% of the jobs today—indicative
`of trends elsewhere that buck those
`occurring in North America.
`North America remains
`the dominant manufacturer
`of proppant (Fig. 7). The fi rst
`non-US plant designed to produce
`fracture sand meeting API RP 56
`recommendations was built in
`1985 by Colorado Silica Sand near
`Chelford, England. A select few
`small natural-sand and resin coating
`operations followed in countries
`such as England, Denmark, Poland,
`and Saudi Arabia. But, according to
`Olmen, the real development outside
`North America has been in the
`production of high-strength ceramics
`and sintered bauxite. Brazil, Russia,
`and China, for example, have
`established substantial synthetic-
`proppant manufacturing capacities,
`all of which export to North America.
`
`The Vital Need for Fluids
`Vast shales are the deposits of oceans
`that existed in the Paleozoic and
`Mesozoic eras and as such present
`resources whose steady exploitation
`will last many decades—even
`centuries. Plenty of these shales
`were in fact the known source rocks
`for many already widely developed
`oil and gas formations. Now these
`source rocks are themselves turning
`out to be excellent reservoirs.
`However, outside North
`America, such resources represent
`a far longer-term frontier, with most
`hydraulic fractures still performed
`on conventional formations, which
`often resp