articol mpg mai 2013

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Fracturarea/ fisurarea hidraulic vs. seismicitatea indus

Dr. ing Ion Irimia ZECHERU

Expert CEN/ ISOSIPG Bucureti

Frackingul, abrevierea popular a fracturrii/ fisurrii hidraulice reprezint un proces n care sunt deschisefisuri n roci sub suprafaa pmntului i extinse de produse chimice i lichide injectate, la presiune nalt;

utilizate n special pentru a extrage gaze naturale sau petrol (problema isturilor bituminoase).

The International Energy Agencyestimeaza resursele de gaze de ist recuperabile punct de vedere tehnic la

aproximativ 208 bilioane de metri cubi(cca 7,3 cvadrilioane picioarecubice). ntre timp, aceeai Agenie

estimeaz c producia de gaze naturale va crete de la 3276 miliarde de metri cubi la 5112 miliarde de

metri cubi pn n 2035, prin tehnologii n care fracking va deveni mai utilizat.

Acest potenial enorm este doar nceputul pentru o lovitur de pia n care frackingul crete n

popularitate n Statele Unite i, ntr-o msur mai mic, in strintate.

US Energy Information Administration estimeaz c 7600 miliarde de metri cubi de gaze de ist vor fi

produse n SUA in 2012, n crestere cu 11,6% fa de 2011, iar producia total de gaze naturale este de

ateptat s creasc cu 4% pn la 5% pe an *a se vedea, de asemenea, un mai profund Uit-te la industria

mrfurilor Americii+. minitrii, sau 7,3 metri cubi cvadrilion.

Cele mai mari oportuniti de fracking n SUA n zcmintele de ist includ:

Barnett Shale, Texas

Bakken Shale, North Dakota Haynesville Shale, Louisiana

Marcellus Shale, Appalachian Basin

Raton Basin, Colorado

n ciuda succesului din Statele Unite, frackingul s-a rspndit lent n alte ri din ntreaga lume. Multe

guverne, cum ar fi i cele din Europa, Asia, Africa i America de Sud, proprietare de drepturi de minerale,

au creat puine stimulente pentru firmele private. Practic, fracturarea/ fisurarea hidraulic a fost, de

asemenea, suspendattemporar n Marea Britanie, dup ce, o serie de cutremure mici, au creat unele

Procesul fracturrii sine nu provoac cutremure; dar n unele cazuri, utilizarea sondelor subteran de

injecie (pentru depozitare) au produs cutremure. Activitatea seismic indusde la mai multe activiti de

energie subteran nu este un fenomen nou i a fost monitorizat ndeaproape de ctre Departamentul de

Energie DOE din SUA.

Dup o serie de cutremure, de intensitate variind de la 2,1 pn la 4,0 grade pe scara Richter, n Ohio i

Arkansas, apropiere de site-uri de petrol i gaze, a fcut ca populaia s-i exprime ingrijorarea cu privire la

operaiile viitoare care rezult din fracturarea/ fisurarea hidraulic, dei procesul de fracking n sine nu

produce aceste cutremure.


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Utilizarea injeciei n zcmnt, un mod eficient i rentabil de a dispune de apele srate uzate, a produs

activitatea seismic. Dei destul de rare, cazurile de activitate seismic (din 30.000 de sonde de injectie, au

existat doar opt evenimente de seismicitate indus), dintre care niciuna nu a provocat pagube materiale

semnificative sau prejudicii, au creat panic n rndul populaiei.

Activitatea seismic ca urmare a activitii din subteran nu este, de asemenea, un fenomen nou.

Departamentul de Energie-DOE al SUA a observat i monitorizat activiti seismice induse de activitile

legate de energienc din anul 1930. n timp ce companiile care induc activitatea seismic ar trebui s fie

rspunztoare pentru orice daune pe care le produce, solicitrile privind interzicerea utilizrii de sondelor

de injectie subterande fracturare hidraulic sunt nefondate.

Fracturarea/fisurarea rezult din pomparea unui fluid vscos newtonian incompresibil la admisia fracturii,

iar debitul n fractura este modelat de teoria lubrifierii. Deformarea rocii se presupune ca poroelastic.

Scurgerean roca gazd este considerat a ine cont de efectele de difuzie.

Criteriul de propagare este de tipul coeziv.

Analiza cu metoda elementuui finit a fost efectuat pentru a calcula presiunea de fracturare/ fisurare i

dimensiunile fisurii ca funcie de timp i lungime. Sa constatat c sunt necesare presiuni mai mari pentru a

extinde o fractura ntrun mediu poroelastic dect ntr-un mediu elastic, iar profilurile create de fisurile

poroelastice sunt mai dezvoltate. S-a constatat c comprimarea de grunijoac un rol minor i nu are ca

rezultat o diferen semnificativ n presiunile fluidelor i dimensiunile fisurii. Profiluri de fisuri mai mari

sunt obinute cu rate de injecie mai mari. Presiunile fluidului i deschiderile fisurii sunt mai mari n cazul

unei formaiuni denalt permeabilitate1.

Tehnicile de fracturare/ fisurare hidraulic au fost experimentate n ani de dezvoltare/ explorare n diverse

zcmintede gaze de ist, n special n Barnett Shale din Texas (figura nr. 1).

Cele mai multe mbuntiri s-au concentrat pe natura aditivilor de fracturare/ fisurare-fracing i a

proppantului-agenul de armare a gurii de sond, cum ar fi nisipul fin sau ceramic, material folosit n

procesul fracking.

Astzi, stimularea zcmntului n formare este o operaiune extrem de specializat, care utilizeazsimularea/ modelarea computerizat pentru a proiecta demararea procesului de fracturare/ fisurare,

dezvoltarea specificaiilor privind volumele de lichid i proppant care urmeaz s se utilizeze, calcularea

presiunii necesare i determinarea compoziiei lichidului fracking.

1http://ascelibrary.org/
http://ascelibrary.org/doi/abs/10.1061/%28ASCE%29GM.1943-5622.0000121?journalCode=ijgnaihttp://ascelibrary.org/doi/abs/10.1061/%28ASCE%29GM.1943-5622.0000121?journalCode=ijgnai


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Figura nr. 1 Evoluia tehnologiei de fracturare/fisurare hidraulic(Nuclear Stimulation-stimulare nuclear, Massive Hydraulic Fracture-fisurare hidraulicmasiv, Precise size and precise location-dimensiune

precis i localizare precis, 1960s, 1980s, 2000s-anii 1960, 1980, 2000)

Aceste date sunt integrate litologic i cu alte caracteristici unice de formare, cum ar fi adncimea,

temperatura i maturitatea termic i caracteristicile structurale ale istului.mpreun, aceste aspecte sunt

utilizate pentru a determina "fracabilitatea" de formare.

Forarea orizontal a zcmntului i finalizarea reprezint o alt tehnologie folosit n explorare n scopul

creterii productivitatii unui zcmnt de gaz prin maximizarea lungimii gurii de sond prin formare

int.

Practicile curente de foraj, de exemplu, n istul Marcellus din Pennsylvania utilizau ambele foraje, att cel

tradiional "vertical" i ct i orizontal; n timp ce forajul vertical poate fi expus la mai putin de 50 de metri

de formare, sondele orizontale sunt dezvoltate cu un foraj lateral de prelungire pe o lungime de sarcin de

la 2.000 de metri la mai mult de 4.000 metri.

Puurile verticale de forare necesit mai puine investiii de capital, comparativ cu puurile de forare

orizontal, dar sunt mai puin productive dect cele orizontale.
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Figura nr. 2 Fisurarea vertical vs. fisurarea orizontal(Sursa: JuneWarren Publishing, 2008)

Cu toate acestea, indiferent de tehnica de finalizare, ambele puuri de sond, verticale i/ sau orizontale,

completate n formaiuni etane la gaze, necesit, de obicei, un anumit tip de formare cum ar fi stimularea

fracturrii/ fisurrii hidraulice.

Atunci cnd se foreaz ntrun zcmnt de gaze de ist sau ntro alt formaiune de petrol i gaze sunt

instalate iniial un ir de evi sau o conduct de dirijare, pentru a preveni prbuirea materialelor

neconsolidate, cum ar fi solul, nisipul i pietriul rezultate n timpul de forrii zcmntului. Apoi, un

"ir de suprafa" sau o coloancu diametru mai mic dect conducta de dirijare este instalat dup foraj,

mai jos de ntreaga lungime vertical a apelor subterane proaspete.

Aceast coloantrebuie s fie cimentat n mod corespunztor la suprafa pentru a proteja toate sursele

de ap subteran potabil din activitatea de producie legate n gaura sondei care este forat i complet

format.

Dac este prezent i crbunele, un alt ir de coloane va fi instalat pentru a izola aceast strat.


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Un alt coloan intermediar poate fi, de asemenea, instalat n anumite condiii ca s izoleze, s

stabilizeze sau s ofere un control mai bun la o adncime mai mare dect cea prevzut de carcasa de

suprafa sau carcasa de protecie a crbunelui. Fiecare coloanva fi mai adnc, dar succesiv mai mic n

diametru.

Aa cum am menionat mai sus, spaiul inelar dintre sond i fiecare rnd de coloan este de obicei

cimentat la suprafa sau la o nlime prescris deasupra fundului coloanei, pentru a asigura izolarea i

protecie a fiecrei zone (figura nr. 3).

Figura nr. 3 Poziionarea carcaselor(Wellhead-gura sondei, cement-ciment, conductor casing-coloan, burlan de foraj, surface casing-coloan de suprafa, de ancoraj,drilling fluid-

fluid de foraj,intermediate casing-coloanintermediar, soil-sol, aquifer-acvifer, impervious rock layers-straturi de roc nepenetrabil)

(Sursa: EnergyFromShale.org)

n cele din urm, esteforat un interval de producie, care poate fi de cteva zeci de metri pn la cteva

sute de metri ntrun vertical sau pn la cteva mii de metri ntrun zcmnt orizontal.

Aceast zon este de obicei analizat electronic sau "conectat" la o companie care este

specializat n acest serviciu i se realizeaz prin coborrea un dispozitiv electronic, pe un fir


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n gaura sondei, n cazul n care sunt analizate date referitoare la porozitate, densitate i alte caracteristici

pentru a determina potenialul de producie al formrii. Dup ce zcmntul a fost conectat, carcasa de

producie este instalat n sond i cimentat pentru a izola aceste zone.

Fracturarea/ fisurarea hidraulic poate fi efectuat n mai puin de un singur interval dintr-un pu vertical.

Cu toate acestea, sondele orizontale, n virtutea lor, au o lungime semnificativ de la gura sondei pn la

inta de formare, n general, sunt izolate pe mai multe intervale discrete de -a lungul orizontal al gurii

sonde (aproximativ 4-20 intervale pentru fiecare gaur orizontal), fiecare interval necesitnd propria

scen de fracing.

Acest lucru se datoreaz dificultilor n meninerea presiunii suficiente pentru a induce fracture/fisuri pe

ntreaga lungime dintr-o parte a zonei.

Fiecare interval izolat ntr-o operaiune de fracing, dac e vorba de un zcmnt vertical sau un zcmnt

orizontal, este supus la o secven specific de fluide cu aditivi, fiecare cu propriul su scop de inginerie

pentru a facilita producerea de gaze din pu.

De exemplu zcmntul Marcellus Wells de gaze de ist utilizeaz de obicei la fracturarea/ fisurarea

hidraulic un lichid pe baz de ap, cunoscut sub numele "slickwater"(ap lucioas).

"Slickwater"este compus predominant din ap, pompat la presiune mare, cu cantiti mai mici de nisip,

mpreun cu concentraiile foarte diluate ale anumitor aditivi i substane chimice destinate pentru a

stimula formarea, a spori ntoarcere sau "flowback" soluiei slickwater, dup stimularea zcmntului i de

a crete producia de gaz din ist.

Chimia special a lichidului frac poate varia de la zcmnt la zcmnt.

Termenul "slickwater" se refer la ageni de reducerea frecrii, cum ar fi clorura de potasiu,

poliacrilamida sau alte substane chimice, adugate n ap pentru a reduce presiunea necesar pomprii

lichidului n gaura de sond.

Aceti aditivi pot reduce frecarea tubular n gaura de sond cu 50 pn la 60%.

O secven de aditivi de fracing pentru un anumit interval este format de obicei din:

1. Etapa de acid, constnd din mai multe mii de litri de ap amestecat cu un diluat acid, cum ar fi acidulclorhidric sau muriatic. Acest lucru servete s elimine resturile de ciment din gaura de sond i s ofere o

conduct deschis pentru alte fluide de fracing, prin dizolvarea carbonailor minerali i s deschid

fracturi/ fisuri lng gaura de sond.

2. Etapa tampon, format din aproximativ 500.000 de litri de slickwater fr materialul proppant. Etapa

tampon de slickwater umple gaura de sond cu soluie slickwater (descris mai jos), se deschide formarea

i ajut la facilitarea fluxului i plasarea de material proppant.

3. Etapa secvenei prop, care poate consta din mai multe substadii de ap combinat cu materialul

proppant, care const dintr-o plas nisip fin sau material ceramic, destinat s menin deschise, sau

fracturile/ frisurile create i/ sau s mbunteasc fracingul n timpul funcionrii n timp ce presiunea


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este mai redus. Aceast etap poate utiliza colectiv cteva sute de mii de litri de ap. Materialul Proppant

poate varia de la o dimensiune a mai fin particulei pn la o dimensiune mai grosier a particulei n timpul

acestei secvene.

4. Etapa de splare, care const dintr-un volum suficient de ap proaspt pentru a spla excesul de

proppant din gaura sondei.

Ali aditivi utilizai n mod obinuit n soluia fracing angajai, de exemplu n puurile de sond din

zcmntul de gaze de ist Marcellus, includ:

- o soluie de acid diluat, aa cum este descris n prima etap, utilizat n timpul secvenei iniiale de fracing,

care cur cimentul i molozul n jurul perforaiilor pentru a facilita soluiile slickwater ulterioare, angajate

n fracturarea formaiunii zcmntului;

- un biocid sau dezinfectant, folosit pentru a preveni dezvoltarea bacteriilor n zcmnt, care poate

interfera cu funcionarea fracing. Biocidul const de obicei n soluii pe baz pe bromsau glutaraldehid.

O secven cu inhibitor, cum ar fi etilen glicol, utilizat pentru a controla precipitarea ctorva minerale:

carbonai i sulfai;

- controlul fierului / ageni de stabilizare, cum ar fi acidul citric sau acidul clorhidric, utilizat pentru a inhiba

precipitarea compuilor de fier prin pstrarea lor ntr-o form solubil;

- frecare agent reductor, de asemenea, descris mai sus, cum ar fi clorura de potasiu sau compuii pe baz

de poliacrilamid, utilizai pentru a reduce frecarea tubular, ulterioar reducerii presiunii necesare pentru

a pompa fluidul n gaura sondei. Aditivii pot reduce frecarea tubular de la 50 pn la 60%.

Aceti compui de reducere a frecrii reprezint componeni "slickwater" al soluiei fracing.

- inhibitori de coroziune, cum ar fi N, N-dimetilformamid i de extragere a oxigenului, precum bisulfitul de

amoniu, sunt utilizate pentru a preveni degradarea carcasei de oel a zcmntului.

- ageni de gelifiere, cum ar fi guma guar (un aditiv alimentar comun), pot fi utilizai n mici componente

pentru ngroarea soluiei pe baz de ap pentru a ajuta la transportul materialului proppant

- ocazional, un agent de reticulare va fi utilizat pentru a mbunti caracteristicile i capacitatea agentului

de gelifiere s transporte materialul proppant.Aceti compuipot conine acid boric sau etilen glicol. Cnd sunt adugai aditivii reticulari, mai trziu n

etapa frac, este frecvent adugat o soluie de ntrerupere, pentru a provoca agent de gelifiere-

mbuntit a evacurii lichidului din gaura de sond, fr a introduce din nou nisip/ material proppant.

Aditivii menionai mai sus sunt componente relativ-comune ale unei frac pe baz de apsoluie folosit n

general n formaiunile de gaze de ist Marcellus n Pennsylvania.

Cu toate acestea, este important de reinut c nu toi aditivii enumerai aici sunt utilizai n fiecare din

operaiunile de fracturare/fisurare hidraulic; mai exact, "amestecul" i proporiile din aditivi vor varia n

funcie de caracteristicile specific site-ului, cum ar fi adncime, grosime i alte caracteristici de formare a

intei.


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Soluii pe baz de azot sunt, de asemenea, folosite ocazional pentru a stimula locaiile de gaz de ist.

Aceast " spum" are de obicei nevoie de doar 25% din necesarul de ap necesar pentru o slickwater frac.

Cu toate acestea, aceast spum pe baz de azot este eficient numai n formaiuni care locuiesc la

adncimi relativ superficiale.

Fracturarea/ fisurarea hidraulic folosete lichidul format din ap, proppant i produsele pe care le folosim

n fiecare zi.

Ap i proppantul folosii pentru a pstra fisurile deschise, alctuiesc 99,5% din materialele folosite pentru

a fracturarea/ fisurarea unui zcmnt. Restul este format din ingredientele pe care le folosim n fiecare zi,

la domiciliu sau la locul de munc - lucruri utilizate n produsele alimentare, aditivi alimentari si

conservanti, cosmetice i alte produse farmaceutice, detergeni de vase, detergeni de rufe, aspiratoare de

uz casnic, sare de mas, antiperspirante i de purificare a apei.


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2012 Guide to Natural Gas Hydraulic Fracturing from Shale Formations: Improving the Safety and Performance of

Hydraulic Fracturing and Fracking


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Friday, April 19, 2013

December 2011 Editor's ChoiceBack to archivesR&D Areas Key To Improving Fracturing

By Guy Lewis and Kent Perry

DES PLAINES, IL.Along with horizontal drilling, enhanced 3-D seismic imaging and other technological advancements, the hydraulic fracturing of gas shale and tight

gas sands have transformed the U.S. energy picture and hold the potential to have a similar impact globally.

In ultralow-permeability shale and tight sand reservoirs, hydraulic fracturing is critical to creating permeability to enable commercial flow rates. Since the first commercial

use of the technology in 1947, it has been used in more than 1 million wells and has helped to produce more than 600 trillion cubic feet of natural gas and 7 billionbarrels of oil. The payoff to developing hydraulic fracturing advances has been extraordinary in bringing new life to old wells and unlocking the potential of oil and gas

resources from reservoirs with low permeability.

Todays research focuses on continuing to fine-tune the approach with more precise sizing and placement through multistage fracturing. Improvements will enable further

reductions in the environmental footprint and enhanced productivity per application. While different well sites require different mixes of frac fluids depending on the

composition of the rock bed and other factors, almost all mixtures are comprised of more than 95 percent water.

Environmental Footprint

Many concerns have been raised associated with the environmental footprint of hydraulic fracturing. In part, this is the result of significant activity taking place in

populated areas that have little experience with natural gas exploration, drilling and production. The vast majority of applications are performed without incident, but good

news is not news. For the most part, hydraulic fracturing is an invisible process with high visibility put on certain activities that support it.

These include water delivery trucks (50 or more per well) that bring traffic, noise, dust and local water requirements. Produced water handling then requires lined pits,

disposal trucks, chemical handling, and on-site treatment/recycling, and all of these activities provide the potential for spills. The potential is there for environmental

impact and the industry is becoming increasingly proactive in reaching out to affected communities. Part of the challenge is that several potential concerns get combined

under the heading of hydraulic fracturing. These include the volume of water required, the potential for groundwater contamination, and the potential for spills of water

at the surface. The solution for the industry is doing good science and providing transparency to fracturing activities, both of which the industry is actively engaged in.Beyond the environmental issues, more research and development will enable the effectiveness of hydraulic fracturing to improve. Today, it is an expensive process with

only 50 percent of fractured stages reaching their full potential based on logs. Causes of nonproductive fracture stages include inadequate design, wrong proppant

loadings, poor fluid selection, proppant embedment, poor fracture fluid cleanup, water blockage of permeability, and poorly understood reservoir compartmentalization.
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Much progress has been made to date, but opportunities remain to improve the effectiveness of fracturing through improved diagnostics, leading to improved fracture

design, better understanding of fracture fluid migration, optimizing proppant loadings, ensuring the right fluids are used, considering alternatives to hydraulic fracturing,

risk modeling to quantify potential negative impacts, and improving rock mechanics models for assessing impacts of well construction and completion techniques.

Technological Evolution

Today, the evolution of lateral and horizontal drilling technology is beginning to allow the development of unconventional resources through the placement of smaller well

bores into exactly the area and location required for optimum production. Figure 1 illustrates the evolution of the technology over the past four decades, with horizontal

drilling and multistage fracturing combining to allow operators to stimulate substantially more reservoir volume yet achieve ever-more precise placement and treatment

size.

FIGURE 1

Evolution of Hydraulic Fracturing Technology

In order to continue this trend in efficiency, a large portion of the formation containing the hydrocarbons has to be exposed to the well bore and stimulated to enhance

permeability. This can only be achieved if the well bore follows the bedding plane of the formation for long distances, which requires long-lateral horizontal wells

completed in multiple stages along the entire length of the lateral.

The effectiveness of horizontal wells can be directly measured by production performance, which is dependent on well spacing, lateral length and orientation of the

lateral well bore relative to the minimum in situ stress of the formation. Optimal spacing of horizontal wells will enable maximum recovery of hydrocarbons between two

wells and reduce the hydrocarbons left behind to be recovered by future infill wells. The horizontal well bore must be positioned in such a way that when fracturing

operations are performed, the hydraulic fractures emanating from the well bore create a network of hydraulically induced fractures coupled with natural fractures, thus

enhancing production.

FIGURE 2

Fracture Geometry Based in Well Bore Position

Relative to In Situ Stress Orientation

Transverse Fractures

A horizontal well bore positioned normal to the maximum in situ stress provides the most complex network of hydraulic fractures (as shown in Figure 2), because it

promotes a series of transverse fractures along the horizontal lateral. The complex fracture network increases the effective permeability of the reservoir, thereby

enhancing production.

Post-fracture stimulation diagnostics are used to determine the overall position of induced hydraulic fractures and to ascertain the amount of the reservoir that was

stimulated, or the stimulated reservoir volume (SRV), as shown in Figures 3A and 3B. Technologies that enable the determination of one or both of these parameters

include net pressure matching, tiltmeter mapping, bore hole microseismic, temperature, chemical and radioactive tracer surveys.

FIGURE 3A
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Microseismic Event Locations

FIGURE 3B

Estimated Stimulated Reservoir Volume

Net pressure matching was refined in vertical well bores with single fracture treatments and provides insight into the geometry of the created fracture by matching the

pressure response. In order for net pressure matching to be reliable, geomechanical reservoir properties have to be accurately modeled in a fracture simulator. Tiltmeter

surveys utilize tiltmeters positioned either in the well bore or on the surface and measure the shift of the rock induced by hydraulic fractures. This technology is best fordetermining fracture azimuth. Additionally, depending on the location of the tools, fracture height and length can be inferred.

Bore hole microseismic surveys utilize an array of geophones positioned in an offset well near the stimulated well. The geophones record microseismic signals

(compressional and shear wave arrivals) generated by the propagation of the hydraulic fractures. This technology can measure the spatial and temporal changes of

hydraulic fractures. Determining the position of the microseismic source greatly depends on the accuracy of the velocity model used to describe the rock strata through

which the signal propagates. Various methods are used to generate the velocity model, including seismic profile surveys, acoustic logs and check shots.

In addition to enhanced diagnostic technologies, the capability to detect sweet spots in real time while drilling is under development. Combined with fracture steering and

orientation control, there is the promise of a future where drilling and completion technologies can be optimized to match the characteristics of a reservoir and tailor the

approach to the specific circumstance.

Great Strides

Operators also continue to make great strides to manage environmental challenges. One of the most important emerging developments has been the practice of reusing

the flow-back water from one well for part of the volume required for the next wells hydraulic fracturing effort. Typically, about 25 percent of the water injected flows back

over the first few weeks after hydraulic fracturing and the well is turned to production. As a result, this reuse reduces the potential for environmental impact, reduces ton-

miles required in water transportation, decreases air emissions, decreases carbon footprint, lowers truck traffic densities, reduces road wear and generally leads to

greater stakeholder acceptance.

Even in the best case scenario, fracturing support is still transportation-intensive, with the 1 million gallons of water flowing back from one well requiring more than 200

truckloads and four times that typically needed in total for the next well.

In addition to reuse of the flow-back water, operators sometimes dispose of flow back and produced water by deep well injection at Class II wells, but this op tion only is

available in regions where the geology is suitable for deep injection and the wells have been drilled. Reintroducing the water from hydraulic fracturing into surface or

ground water can be environmentally safe if the water is sufficiently treated, but these treatment technologies can be very expensive. Developments continue within the

industry to reduce the cost of these treatment technologies.

In the meantime, some water treatment is important for reuse to protect equipment and the shale formation from damage. This portfolio of options allows operators to be

flexible and allow for the freshwater requirements for shale gas development to be minimized. More research is required to quantify the impact of varying water quality on

formation quality.

Fracturing fluid migration into freshwater aquifers has not been observed. Although it is not demonstrated that fractures can reach fresh groundwater, there is the

potential for spills at the surface and leaks and ruptures in surface casing if cementing jobs are not performed properly. As a result, it is important to understand what is

put into fracturing fluids and promote sustainable operating practices that minimize the risk of surface contamination. Strides have been made to develop more

environmentally benign fracturing fluids and alternatives to the use of water in enhancing permeability, and this is another area of ongoing research efforts.

Future Research AreasHydraulic fracturing has evolved from the performance of a single treatment in a vertical well to multiple treatments in a horizontal well. The technology to adequately

characterize and evaluate the hydraulic fracturing process has been eclipsed by the ability to drill the horizontal well and pump the fracture treatments. A collaborative

industry project to conduct field research experiments on the hydraulic fracturing process would enhance the understanding of the dimensions and productivity of

hydraulically created fractures in long horizontal well completions aiming to develop improved procedures that will be reflected in better well productivity.
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Additional research that should be performed includes novel ideas for creating permeability beyond the hydraulic fracturing process, such as explosives, cryogenic fluids

and novel heating techniques. The potential for improvement is large enough to set goals of future research such as:

Developing the technology and techniques to increase horizontal well performance by up to 100 percent. The benefits could include adding 500 million cubic feet ofreserves (across 1,000 wells), increasing revenue up to $2 billion even at a U.S. gas price of $4.00 an MMBtu, and reducing the environmental footprint by 50 percent

because of increased productivity.

Mitigating air, land and water environmental issues associated with well drilling and completion. Multipad drilling will minimize surface footprint. Reducing fugitivemethane emissions and converting field fleets to operate on natural gas will reduce greenhouse gas emissions. Further enhancements to produced and flow-back water

treatment technology and developing alternatives to using water will reduce net water consumption.

While theoretical and modeling efforts have advanced significantly, the needed next step is to conduct comprehensive and transparent field experiments to verify new

theories to explain the productivity responses from multiple and modified treatments in horizontal well bore geometries. A carefully planned field-based research

experiment similar to what the industry has conducted in past years is overdue. A comprehensive research experiment could lead to significantly improved hydraulicfracturing efficiencies. The set of research topics might include:

Drilling, logging, coring and well completions;

Sidetracking and coring through the fracture domain;

Fracture injection operations;

Direct observation of induced fractures and cuttings in core;

Injection of radioactive solid and fluid tracers/spectral gamma ray logging;

Bore hole imaging using formation micro imager (FMI) tools;

Downhole hydraulic fracturing seismic characterization and ground truth as to the true meaning of signals received;

Surface seismic evaluations;

Hydraulic fracturing seismic model verification and calibration (including directly measuring the exact time of the seismic signals reaching observation wells, and howthose measurements compare to modeled predictions);

The effectiveness of downhole perforating techniques;

Evaluating directional changes in hydraulically induced fractures (e.g., where does the fracture intercept observation wells versus the initiation point?);

Evaluating fracturing fluid and proppant placement;

Assessing the created conductivity as measured with flow between two wells connected by a hydraulic fracture;

Evaluating flow effectiveness and stimulated reservoir volumes; and

Conducting formation evaluation experiments to determine optimum well log suites.

GUY LEWIS is executive director for strategic growth initiatives at the Gas Technology Institute, responsible for developing new growth

opportunities for GTI and developing key strategic global relationships. Previously, Lewis was responsible for GTIs unconventional gas technology development and

collaborative research and development programs. He has extensive experience in strategic planning, performance management and operational leadership in the

energy industry, with a proven track record of developing and implementing innovative strategies and leading transformation initiatives. Before joining GTI, Lewis held

leadership positions at BP and Amoco. He serves on the board of directors of the Research Partnership to Secure Energy for America (RPSEA) and is president of the

GTI Catoosa test drilling facility in Tulsa. Lewis holds a degree in chemical engineering from Northwestern University and an M.B.A. from the University of Chicago.

KENT PERRY is director, exploration and production research, at the Gas Technology Institute in Des Plaines, Il. At GTI, he has responsibility

for planning and managing a research program for recovering unconventional natural gas in the United States. He also serves as team leader, unconventional gas, for

RPSEA. Perrys experience includes 30 years of natural gas engineering and gas production responsibilities, including gas storage engineering for Northern Illinois Gas

Co., production engineering with Kansas-Nebraska Natural Gas Co., and exploration and production for Michigan Energy Resources Co. He is a past Society of

Petroleum Engineers distinguished lecturer on tight gas sands, and has participated in National Petroleum Council studies on domestic natural gas potential. Perry holds

a B.S. in petroleum engineering from Colorado School

Frac FactsTwo Cs Drive Bakken Well Performance - JANUARY 2013

By Chris W right, Mark Pearson, Larry Griff in , Leen Weijers and Br ian Weaver

DENVERThe Bakken/Three Forks play in western North Dakota and eastern Montana is producing 750,000 barrels of oil a day, which is r oughly one-quarter of Iraqi

production or pre-sanctions Iranian production, and it exceeds the entire output of OPEC-member Ecuador. It is for real.


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The Bakken/Three Forks also represents the leading edge of the boom in North American tight-rock, unconventional oil production that now is sweeping the Eagle Ford

in South Texas, the proud Permian Basin, the Utica in Ohio, Niobrara in Colorado, and many more to come.

The unconventional revolution that began only 12 years ago with a surge in natural gas production from the Barnett Shale in Texas has shifted to a focus on producing

oil and natural gas liquids. After delivering abundant natural gas supplies to the United States at less than one-third the cost of any other industrialized nation and stirring

an industrial revival, it is reversing a 35-year decline in U.S. oil production. Growth in domestic oil production over the past year represents more than half of the growth

in total world oil production.

The diversity of completion designs for horizontal drilling and high-intensity, stage fracturing across the Williston Basin, however, shows that companies are drawing

quite different conclusions about their experiences, which is yielding vast differences in production response.

Some production differences can be explained by reservoir quality changes. For example, the last wave was in the higher-permeability and more intensely naturally

fractured Parshall and Sanish fields, while development now is focused on the tighter rock in the Bakken Central Basin. However, much of the production difference is

the result of dramatic differences in completion strategies and fracture design.

A novel completion approach was developed for the Bakken Central Basin that employs plug-and-perf (P&P) technology in an uncemented liner with high-rate, large-

volume, slick-water fracture treatments and the exclusive use of high-quality ceramic proppants. While these jobs can present significant execution challenges, the

superior production results warrant this approach to Bakken Central Basin development and possibly other Bakken areas.

Novel Design Approach

As with cracks on a windshield, hydraulic fractures in reservoir rock do not initiate easily, and growth tends to occur where fractures or points of weakness exist.

Economic production in tight reservoirs is heavily dependent on the extent of reservoir rock contacted and effectively connected to the well bore.

P&P completions begin by creating multiple prefractured-rock initiation points from multiple perforation clusters in each 250-300 foot-long stage interval. Simultaneous

growth of multiple hydraulic fractures results from injecting low-viscosity fluid at sufficient rate to ensure flow is diverted across the four to five perforation clusters

employed in each stage. The low-viscosity fluid also encourages fractures to initiate in other planes of weakness, further enhancing hydraulic fracture complexity and

maximizing contact area within the reservoir.

But simply touching a large amount of reservoir rock is not enough. One must also create sufficient conductivity to allow mul tiphase fluid flow through the fractures and

the dramatic choke that results from convergent flow into a well bore that transversely or obliquely intersects the fracture networks.

Hydraulic fracture height growth above the Bakken formation can be significant, and the poor proppant transport characteristics of slick water keep most of the proppantnear the bottom of the created fractureslikely mostly within the productive 30-80 foot-thick Middle Bakken interval, which is bounded by the Upper and Lower Bakken

shales. When maximizing the contact area and fracture complexity to touch the most rock, creating partial proppant monolayers probably is more the rule than the

exception above the settled proppant pack at the fracture base.

Using small-mesh proppants helps transport them deeper into the fracture system, and stronger ceramic proppants provide the necessary strength to maintain

conductivity. Higher effective stress is carried by individual proppant grains in a partial monolayer, compared with the grain stresses in a conventional proppant pack.

Increasing fracture contact area by several times inevitably reduces the pounds of proppant per square foot of fracture area.

Slick Water Design Physics

How can stimulation engineers design completion and fracture treatments to create hydraulic fractures with the two Cs (contact and conductivity)? We believe there are

three critical components that individually contribute to an improved production response in Central Basin Bakken wells.

First, a P&P completion strategy helps create multiple distinct and distributed initiation points within each fracture stage. Creating several hydraulic fractures 50-60 feet

apart in each stage allows more effective drainage of the tight Bakken reservoir. In contrast, fracturing through sliding sleeves can be expected only to initiate a single

hydraulic fracture per stage, at either a swell packer or another randomly located natural fracture or point of weakness along the lateral length.

FIGURE 1

The ability to create complexity and reservoir contact area through a fracture system depends on the well completion and the fracture treatment design.

In Figure 1, the left picture represents the simple fracture system that likely is created by pumping viscous gel through a sliding sleeve at a moderate injection rate. Once

a fracture is createdpossibly near one of the external packers because of the tensional forces in that areait is very hard to divert fluid flow effectively to initiate other

fractures. Even with high injection rates, it is difficult to induce a second fracture along an unperforated well bore, since the initial fracture can simply open fractionally

wider to accommodate the flow as fracture pressure increases with only the quarter power of injection rate.

On the other hand, a perforated liner, shown on the right side of Figure 1, with several isolated perforation clusters and the total number of perforations engineered to

force flow through nearly all of them, will lead to initiating hydraulic fractures at each clustertypically four or five per stage. Although there is communication along the

backside through the annulus of the uncemented liner, the flow-rate squared dependence of pressure drop through perforations will force nearly all perforations to break

down and initiate hydraulic fractures at each cluster.

Fracture System Complexity

The second critical completion component for Central Basin Bakken wells is slick water, which will help create widespread fracture complexity. A viscous gel encourages

a simpler or more dominant frac system that is more appropriate for higher permeability formations.

Microseismic mapping of Barnett Shale slick-water refracs that were treated initially with cross-link gel reveals both a higher density of microseismic events and wider

dispersion of events, indicating greater fracture system complexity. The production response was improved significantly in the tight Barnett Shale because of increased

surface area from high-rate slick-water fracturing versus conventional gel fracturing.

The low-viscosity fluid is expected to more easily penetrate natural fractures or other planes of weakness, even if these planes are at slightly different orientations than

the preferred fracture plane. In the Barnett Shale, propagation in two distinct orientations was evident from both microseismic and surface tilt fracture mapping, and was

believed to be made possible by the lower horizontal deviatory stress and the presence of natural fractures at a roughly orthogonal orientation with respect to the

preferred fracture plane.
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In the Bakken, the case for complex fracture growth in distinct orientations is less obvious, but a low-viscosity fluid certainly will help to enhance the possibility.

Slick-water treatments are not always easy, and have proven challenging in Middle Bakken horizontal wells. Slick-water treatments exhibit higher premature screen-out

risk in long laterals; are tougher on pumps, fluid ends, power ends, etc.; and present challenges in economically securing the increased volumes of treatment water

required.

In addition to the screen-out risks associated with pumping proppants through a 10,000-foot lateral, Bakken treatments are even more prone to screen-out risks because

of the oblique orientation between well bore and the preferred fracture plane.

FIGURE 2

The connection between the well bore and the far-field fracture becomes more complex when the well is oriented at an oblique orientation with the principle

stress components. In the Williston Basin, the oblique angle originates from the northeast-southwest preferred fracture orientation and the now-dominant

north-south well bore trajectories.

Prior to 2010, operators could elect to permit either a single-section 640-acre well or a dual section 1,280-acre well, but in March 2010, the North Dakota Industrial

Commission placed the remaining extent of the Bakken reservoir on 1,280-acre spacing. This effectively requires operators to drill 9,500-foot laterals in order to hold a

drilling spacing unit (DSU).

This has resulted in wells being drilled primarily in a north-south orientation, while the preferred fracture plane in the Williston Basin is at an oblique angle with an

orientation at about north 50 degrees east. As shown in Figure 2, enhanced screen-out risk is associated with oblique fractures.

While poor proppant transport with slick water in long laterals is a challenge, poor proppant transport in the fracture helps to keep most proppant within the Bakken

interval. Microseismic mapping of Middle Bakken treatments has consistently shown dramatic upward fracture height growth (Figure 3). Slick waters poor proppant

transport helps assure that most of the proppant is not transported upward, out of the Bakken, and instead remains within the Middle Bakken pay interval.

FIGURE 3

Poor proppant transport in slick-water treatment is beneficial for in-zone proppant placement. Upward out-of-zone fracture height growth is virtually

impossible to control in the Bakken, even at low injection rates, while downward growth generally is limited because of higher stresses in the Three Forks

formation. As the hydraulic fracture system generally grows upward by hundreds of feet into the Lodgepole formation, poor proppant transport minimizes

proppant placement across this zone with potentially high water cut and the presence of hydrogen sulfide, placing most of the proppant in the zone where itcan aid Bakken oil production.

Ceramic Proppant

The third critical component for an improved production response in Central Basin Bakken wells is a high quality ceramic proppant, which creates a long-term conductive

connection between the reservoir and the well bore. Maximizing reservoir contact area would all be for naught if one couldnt also sustain oil flow from much of the

contacted rock.

Smaller proppant sizes (40/70 mesh) are used to prop deep into the created complex fracture network, while moderate-size proppant (30/50 mesh) provides conductivity

in the main fracture system. The low proppant concentrations (generally up to one pound per gallon) in Bakken slick-water treatments most likely result in a combination

of settled pack and partial proppant monolayers, and proppant bridging at pinch points (Figure 4). The higher point loading is handled better by stronger ceramic

proppant, and the created distribution provides enough strength to keep the system conductive.

FIGURE 4
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Moderate-rate gel treatments through sliding sleeves most likely create only one or two initiation points along the lateral interval between swell packers,

whereas high-rate slick-water treatments with fracture initiation through perforations greatly enhance fracture complexity. As a result of the much greater

reservoir contact area, there is greater need for high-strength proppant in the slick-water application, since proppant is distributed over many smaller

fractures, most likely creating partial proppant monolayers.

Bakken frac fleets typically are composed of six-eight pumping units, since they are required to pump at rates only of 20-50 barrels a minute (bpm). An eight-pump frac

fleet injecting at 40 bpm and 7,500 psi has about 50 percent excess/standby pumping capacity. In order to inject slick-water fracs at up to 80 bpm and 9,500 psi, it is

necessary to have a minimum of 10 pumping units (12 with standby units) in the frac fleet.

While such a frac fleet is standard (and often significantly larger) in most of the gas shale areas that utilize slick-water fracturing, this has not been standard in the North

Dakota pumping service industry. For this reason, and also in part because of the lack of pumping service capacity in the basin during late 2010 and 2011, Liberty

Resources developed its own capability to pump high-rate slick-water fracs by launching Liberty Oilfield Services.

Proof In Production

The Bakken is an overpressured reservoir with pore pressure gradients in excess of 0.75 psi a foot in the deepest parts of the basin. As a consequence, post-frac flow-

back fluid volumes provide an almost immediate indication of stimulation effectiveness.

It is not unusual to start cutting oil within the first 24 hours of flow back as formation fluids are produced in addition to the fracturing fluid. Maximum production rates

typically are generated during the plug or seat drill-out phase, since reservoir pressure is still charged by the injection of stimulation fluids. However, variation in drill-out

procedures between operators means the initial flow data are not a suitable metric for direct comparison of different completion designs.

Similarly, differences in flow-back procedures and choke settings in the early operating philosophies of different operators also yielded significant variations in 30-day

cumulative production data.

A 2010 study by TudorPickeringHolt, which was conducted across all Bakken development regions of the Williston Basin, gave correlations of R2 = 0.96 between 90-day

cumulative production and forecast estimated ultimate recoveries predicted from historical well production. Therefore, 90-day production results are believed to be a

good metric for long-term production performance, and are used to compare the efficiency of completion procedures.

To evaluate production performance for the slick-water-only design, we compared production results in a relatively small area of the Bakken Central Basin, where a

variety of completion designs where implemented in a statistically relevant number of wells. We chose the area within and surrounding Township 156N-R101W inWilliams County, N.D., since this is one of the main areas where Liberty Resources holds acreage.

All these wells have laterals in excess of 9,000 feet in 1,280-acre DSUs, and were stimulated in 26-35 stages with roughly 100,000 pounds of proppant per stage. But

the similarities end there. The wells provide a localized comparison of the production performance from the three broad completion approaches employed in the Bakken:

Sliding sleeves were used in cross-linked gel fracture treatments to place either sand or ceramic proppant. About 25 stages were conducted per well, with each s tage

placing 2,800 barrels of clean fluid and 105,000 pounds of 40/70 and 20/40 sand or ceramic proppant.

P&P was employed with hybrid slick water and cross-linked gel to place sand and (mostly) ceramic proppant. Between 26 and 32 stages aimed to place about 3,000

barrels of clean fluid and 122,000 pounds of 40/70 sand, 20/40 sand and (mostly) 20/40 ceramic proppant per stage.

P&P was used with high-rate slick water to place ceramic proppant. Thirty-five stages generally placed 7,000 barrels of clean fluid and 115,000 pounds of 30/50 and

40/70 ceramic proppant per stage.

FIGURE 5

This 90-day production bubble map compares gel, hybrid and slick-water treatments within or surrounding Township 156NR101W in Williams County, N.D.

FIGURE 6
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The gel, hybrid and slick-water treatments employed near T156N-R101W resulted in dramatic differences in 90-day production volumes.

90-Day Results

Figure 5 is a 90-day production bubble map with three colors, illustrating the dramatic differences in performance of these approaches in the same neighborhood. Figure

6 shows the 90-day production results sorted by completion strategy within this section of the Bakken, which was localized so that reservoir variability was minimized.

As can be seen, the three completion and stimulation designs have large variations in 90-day cumulative production. Averages range from 19,100 barrels of oil for gel

with sleeves, 28,800 bbl oil for hybrid plug and perf, and 49,300 bbl oil for the slick water only strategy. Clearly, with wellhead commodity prices of more than $80 abarrel, the increased time and costs of the P&P completion design with slick-water fracturing is highly economic.

We also investigated whether the benefits of the slick water-only design extended across the rest of the Central Basin. The answer clearly is yes. As of September 2012,

there were 870 Central Basin wells in the NDICs public database that had at least one month of production data. Of those, 58 were completed with our slick water-only

approach.

FIGURE 7A

Rough Rider Project Area - 870 Wells

(Completions since Jan. 15, 2009, Production through September 2012)

Absolute 30-, 60- and 90-day production responses for all wells in the Central Basin are sorted by operator. Well counts are shown next to the operator

label.

FIGURE 7B

Operator Average Cumulative Bbls Oil/Acre-Ft - 870 Wells

(Completions since Jan. 15, 2009, Production through September 2012)
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Leen Weijers is business manager for Liberty Oilfield Services LLC. He completed his doctoral research at the Faculty of Mining and Petroleum

Engineering at Delft University of Technology in the Netherlands by conducting fracture growth model experiments to investigate the interaction of hydraulic fracturesystems with horizontal and deviated wells. Weijers worked at Pinnacle Technologies between 1995 and 2011, where he initially focused on helping clients design and

execute hydraulic fracture treatments. Between 1999 and 2006, Weijers was in charge of developing the industrys most widely used fracture growth simulator,

FracproPT.

Brian Weaverjoined Liberty Oilfield Services as sales manager early in 2012. He started in the oil and gas industry as a well stimulation fieldengineer with Schlumberger in Grand Junction, Co., and has worked in the Piceance, Uinta, Green River and Paradox basins. After Schlumberger, Weaver joined

Pinnacle Technologies as a project manager for fracture diagnostics. With Pinnacle, he managed microseismic and microdeformation (surface tilt meter) mapping

projects in nearly every basin in the Rockies as well as projects in Texas, Pennsylvania and Alberta. Weaver earned his mechanical engineering degree from Colorado

State University.

Camp Frack : Whos afraid of hydraulic fracturing ?Posted on September 17th, 2011Jo1 comment

When do micro-seismic events add up to earthquakes ? Landslips ? Tsunamis ? Who really knows ? These are just a few questions amongst many

about underground mining techniques that will probably never be properly answered. Several mini-quakes were suggested to be responsible forthe

shutdownof Cuadrillas activities in Blackpool, north west England early in 2011, and there have beenunconfirmed links between tremors and frackingin

the United States of America, where unconventional gas is heavily mined.

It is perhaps too easy to sow doubt about the disbenefits of exploding rock formations by pressure injection to release valuable energy gasesmanylegislativeandpublic consultationhurdles have been knocked down by themerest flickofthe public relations wristof the unconventional fossil

gas industry (and its academic and consultancy friends).

The potential to damage the structure of the Earths crust may be the least attributable andleast accountableof hydraulic fracturings suspected

disadvantages, but it could be the most significant in the long run.Sciencebeingconductedinto the impact on crust stability from fracking and other
http://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/http://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/http://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/http://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/http://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/#commentshttp://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/#commentshttp://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/#commentshttp://noshalegas.wordpress.com/2011/06/02/shaken-but-not-stirred-a-cuadrilla-cocktail/http://noshalegas.wordpress.com/2011/06/02/shaken-but-not-stirred-a-cuadrilla-cocktail/http://noshalegas.wordpress.com/2011/06/02/shaken-but-not-stirred-a-cuadrilla-cocktail/http://noshalegas.wordpress.com/2011/06/02/shaken-but-not-stirred-a-cuadrilla-cocktail/http://www.telegraph.co.uk/finance/personalfinance/offshorefinance/8488166/Frack-and-ruin-the-rise-of-hydraulic-fracturing.htmlhttp://www.telegraph.co.uk/finance/personalfinance/offshorefinance/8488166/Frack-and-ruin-the-rise-of-hydraulic-fracturing.htmlhttp://www.telegraph.co.uk/finance/personalfinance/offshorefinance/8488166/Frack-and-ruin-the-rise-of-hydraulic-fracturing.htmlhttp://cleantechnica.com/2010/03/20/its-about-fracking-time-u-s-epa-lights-a-fire-under-hydraulic-fracturing/http://cleantechnica.com/2010/03/20/its-about-fracking-time-u-s-epa-lights-a-fire-under-hydraulic-fracturing/http://cleantechnica.com/2010/03/20/its-about-fracking-time-u-s-epa-lights-a-fire-under-hydraulic-fracturing/http://www.parliament.uk/business/committees/committees-a-z/commons-select/energy-and-climate-change-committee/news/new-report-shale-gas/http://www.parliament.uk/business/committees/committees-a-z/commons-select/energy-and-climate-change-committee/news/new-report-shale-gas/http://www.parliament.uk/business/committees/committees-a-z/commons-select/energy-and-climate-change-committee/news/new-report-shale-gas/http://online.wsj.com/article/SB10001424052702303491304575187880596301668.htmlhttp://online.wsj.com/article/SB10001424052702303491304575187880596301668.htmlhttp://online.wsj.com/article/SB10001424052702303491304575187880596301668.htmlhttp://online.wsj.com/article/SB10001424052748703712504576232582990089002.htmlhttp://online.wsj.com/article/SB10001424052748703712504576232582990089002.htmlhttp://online.wsj.com/article/SB10001424052748703712504576232582990089002.htmlhttp://www.naturalgaseurope.com/lucas-cuadrilla-shale-gas-successhttp://www.naturalgaseurope.com/lucas-cuadrilla-shale-gas-successhttp://www.naturalgaseurope.com/lucas-cuadrilla-shale-gas-successhttp://georgewashington2.blogspot.com/2011/08/its-official-human-activity-can-cause.htmlhttp://georgewashington2.blogspot.com/2011/08/its-official-human-activity-can-cause.htmlhttp://georgewashington2.blogspot.com/2011/08/its-official-human-activity-can-cause.htmlhttp://www1.gly.bris.ac.uk/~JamesVerdon/PDFS/JamesVerdonThesis.pdfhttp://www1.gly.bris.ac.uk/~JamesVerdon/PDFS/JamesVerdonThesis.pdfhttp://www1.gly.bris.ac.uk/~JamesVerdon/PDFS/JamesVerdonThesis.pdfhttp://shalegaswiki.com/index.php/Hydraulic_fracturinghttp://shalegaswiki.com/index.php/Hydraulic_fracturinghttp://shalegaswiki.com/index.php/Hydraulic_fracturinghttp://www1.gly.bris.ac.uk/~JamesVerdon/PDFS/JamesVerdonThesis.pdfhttp://georgewashington2.blogspot.com/2011/08/its-official-human-activity-can-cause.htmlhttp://www.naturalgaseurope.com/lucas-cuadrilla-shale-gas-successhttp://online.wsj.com/article/SB10001424052748703712504576232582990089002.htmlhttp://online.wsj.com/article/SB10001424052702303491304575187880596301668.htmlhttp://www.parliament.uk/business/committees/committees-a-z/commons-select/energy-and-climate-change-committee/news/new-report-shale-gas/http://cleantechnica.com/2010/03/20/its-about-fracking-time-u-s-epa-lights-a-fire-under-hydraulic-fracturing/http://www.telegraph.co.uk/finance/personalfinance/offshorefinance/8488166/Frack-and-ruin-the-rise-of-hydraulic-fracturing.htmlhttp://noshalegas.wordpress.com/2011/06/02/shaken-but-not-stirred-a-cuadrilla-cocktail/http://noshalegas.wordpress.com/2011/06/02/shaken-but-not-stirred-a-cuadrilla-cocktail/http://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/#commentshttp://www.joabbess.com/2011/09/17/camp-frack-whos-afraid-of-hydraulic-fracturing/


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well injection techniques could rule out a wide range of geoengineering on safety grounds, such as Carbon Capture and Storage proposals. If we

cant safely pump carbon dioxide underground, we should really revise our projections on emissions reductions from carbon capture.

[Camp Frackis under canvas in Lancashire protesting about the imposition of hydraulic fracturing on the United Kingdom. ]

Ultimately, the results of this study are expected to inform the public and provide decision-makers at all

levels with high-quality scientific knowledge that can be used in decision-making processes.

Criteria for Case Study Location SelectionThe sites were identified, prioritized and selected based on a rigorous set of criteria and represent a wide range of conditions and

impacts that may result from hydraulic fracturing activities. These criteria included:

proximity of population and drinking water supplies,

evidence of impaired water quality (retrospective only),

health and environmental concerns (retrospective only), and

knowledge gaps that could be filled by the case study.

Sites were prioritized based on:

geographic and geologic diversity,

population at risk,

site status (planned, active or completed),

unique geological or hydrological features,

characteristics of water resources, and

land use.

http://anga.us/issues-and-policy/safe-and-responsible-development/hydraulic-fracturing-101#.UXEzGqJmjTq

http://www.psr.org/environment-and-health/environmental-health-policy-institute/hydraulic-fracking.html

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm

http://www.epa.gov/history/publications/hist_pr.html
http://www.campaigncc.org/campfrackhttp://www.campaigncc.org/campfrackhttp://www.campaigncc.org/campfrackhttp://anga.us/issues-and-policy/safe-and-responsible-development/hydraulic-fracturing-101#.UXEzGqJmjTqhttp://anga.us/issues-and-policy/safe-and-responsible-development/hydraulic-fracturing-101#.UXEzGqJmjTqhttp://www.psr.org/environment-and-health/environmental-health-policy-institute/hydraulic-fracking.htmlhttp://www.psr.org/environment-and-health/environmental-health-policy-institute/hydraulic-fracking.htmlhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.epa.gov/history/publications/hist_pr.htmlhttp://www.epa.gov/history/publications/hist_pr.htmlhttp://www.epa.gov/history/publications/hist_pr.htmlhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htmhttp://www.psr.org/environment-and-health/environmental-health-policy-institute/hydraulic-fracking.htmlhttp://anga.us/issues-and-policy/safe-and-responsible-development/hydraulic-fracturing-101#.UXEzGqJmjTqhttp://www.campaigncc.org/campfrack


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sursa:http://eidmarcellus.org/
http://eidmarcellus.org/http://eidmarcellus.org/http://eidmarcellus.org/http://eidmarcellus.org/


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A build-tangent and then a higher build-lateral section.


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Hydraulic fracturing has gained a lot of attention recently, as companies scramble to mine the valuable frac sandcontained in the Midwest. While

fracing is new to most people, hydraulic fracturing, though in primitive form, can be traced all the way back t o the 1860s oil industry, when liquid

nitroglycerin (NG) was used to stimulate shallow rock wells in several states around the US. The idea, then referred to as shooting, was to use the

nitroglycerin to break up the formation in which the oil was contained, fostering better flow and retrieval. Extremely fruitful, this idea was carried over

to the water and gas industries1.


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While the 1930s saw small improvements in the pressure parting trend, it wasnt until the late forties when the hydrafrac process really began to

be developed. After much experimentation, a patent was issued to the Haliburton Oil Well Cementing Company (Howco) to use the hydrafrac

process, and in turn, they produced the first two commercial fracturing treatments. As the hydrafrac process spread, more than 3,000 wells per

month were hydrafraced throughout the mid-1950s. It is estimated that fracturing advanced US recoverable reserves of oil by at least 30%, and of

gas by 90%1.

From crude oil to borate gel, all the way to gelled kerosene, many fluids and additives were experimented with throughout history in order to

enhance the hydrafrac process, making it as efficient as possible. The first proppant used was screened river sand. Several other materials were

experimented with as proppants, such as plastic pellets, steel shot, aluminum pellets, high-strength glass beads, rounded nut shells, resin-coated

sands, sintered bauxite, and fused zirconium1.

Technological advancements and the discovery of high quality quartz sand in the Midwest have caused a recent rise in hydraulic fracturing in the

Midwest. Companies are clamoring to mine all the high-value sand they can1.

FEECO has been in thematerial handlingbusiness for over 60 years. Our material handling andthermal processingequipment is robust, built for

longevity, and ready to take on any job. We can supply material handling equipment such as conveyor systems, bucket elevators, rotary dryers, and

rotary coolers to the frac sand industry.Contact ustoday to learn more about our frac sand equipment capabilities.

1. Source:Hydraulic Fracturing: History of An Enduring Technologyby Carl T. Montgomery and Michael B. Smith, NSI Technologies, 2010

The Hydraulic Fracturing Water CycleEPA's study will look at potential impacts of HF at each stage of the HF Water Cycle.

Click on the image below to learn more about the HF Water Cycle.

Stage 1: Water Acquisition1 Large volumes of water are withdrawn from ground water2and surface water3resources to be used in the HF process.

Potential Impacts on Drinking Water Resources

Change in the quantity of water available for drinking

Change in drinking water quality

Top of Page

Stage 2: Chemical Mixing
http://feeco.com/equipment/material-handling/http://feeco.com/equipment/material-handling/http://feeco.com/equipment/material-handling/http://feeco.com/equipment/thermal-processing/http://feeco.com/equipment/thermal-processing/http://feeco.com/equipment/thermal-processing/http://feeco.com/contact-us/http://feeco.com/contact-us/http://feeco.com/contact-us/http://www.jptonline.org/index.php?id=481http://www.jptonline.org/index.php?id=481http://www.jptonline.org/index.php?id=481http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn1http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn1http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn1http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn2http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn2http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn2http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn2http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn3http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn3http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn3http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn3http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn3http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn2http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn1http://www.jptonline.org/index.php?id=481http://feeco.com/contact-us/http://feeco.com/equipment/thermal-processing/http://feeco.com/equipment/material-handling/


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Once delivered to the well site, the acquired water is combined with chemical additives4and proppant5to make the HF fluid.


Release to surface and ground water through on-site spills and/or leaks

Top of Page

Stage 3: Well Injection Pressurized HF fluid is injected into the well, creating cracks in the geological formation that allow oil or gas to escape through the

well to be collected at the surface.


Release of HF fluids to ground water due to inadequate well construction or operation

Movement of HF fluids from the target formation to drinking water aquifers through local man-made or natural features (e.g.,

abandoned wells and existing faults)

Movement into drinking water aquifers of natural substances found underground, such as metals or radioactive materials, which

are mobilized during HF activities

Top of Page

Stage 4: Flowback6and Produced Water7(HF Wastewaters) When pressure in the well is released, HF fluid, formation water, and natural gas begin to flow back up the well. This combination

of fluids, containing HF chemical additives and naturally occurring substances, must be stored on-sitetypically in tanks or pits

before treatment, recycling, or disposal.


Release to surface or ground water through spills or leakage from on-site storage

Top of Page

Stage 5: Wastewater Treatment and Waste Disposal Wastewater is dealt with in one of several ways, including but not limited to: disposal by underground injection, treatment followed

by disposal to surface water bodies, or recycling (with or without treatment) for use in future HF operations. Potential Impacts on Drinking Water Resources

Contaminants reaching drinking water due to surface water discharge and inadequate treatment of wastewater

Byproducts formed at drinking water treatment facilities by reaction of HF contaminants with disinfectants

Top of Page

1Recently, some companies have begun recycling wastewater from previous HF activities, rather than acquiring water from groundor surface resources.

2Ground water is the supply of fresh water found beneath the Earths surface, usually in aquifers, which supply wells and springs. Itprovides a major source of drinking water.3Surface water resources include any water naturally open to the atmosphere, such as rivers, lakes, reservoirs, ponds, streams,impoundments, seas, estuaries, etc. It provides a major source of drinking water.

4Chemical additives are used for a variety of purposes (see examples in Table 4 on page 29 of theHF Study Plan (PDF)). A list ofpublicly known chemical additives found in HF fluids is provided in Appendix E, Table E1 of theHF Study Plan (PDF).

5Proppant is a granular substance such as sand that is used to keep the underground cracks open once the HF fluid is withdrawn.6After the HF fracturing procedure is completed and pressure is released, the direction of fluid flow reverses, and water and excessproppant flow up through the wellbore to the surface. The water that returns to the surface is commonly referred to as flowback.

7After the drilling and fracturing of the well are completed, water is produced along with the natural gas. Some of this water isreturned fracturing fluid and some is natural formation water. These produced waters move back through the wellhead with the

gas.

Contact theEPA's Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources Web editorto ask a question, provide feedback, or report aproblem.

Seismic activity
http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn4http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn4http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn4http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn4http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn5http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn5http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn5http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn5http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn6http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn6http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn6http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn7http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn7http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn7http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn7http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122mailto:[email protected]:[email protected]:[email protected]:[email protected]://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-resources-epa600r-11122http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn7http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn6http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#main-contenthttp://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn5http://www2.epa.gov/hfstudy/hydraulic-fracturing-water-cycle#ftn4


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Hydraulic fracturing creates microseismic events, but the magnitude of these is generally too small to be detected at the sur face according to the'Assessing the environmental risks from shale gas development' study by the Worldwatch Institute. In rare cases, when existing faults are activated,hydraulic fracturing could induce seismicity equivalent to the vibrations of trucks. We evaluate industry-recommended guidance for avoiding inducedseismicity and we apply these practices to our operations as appropriate.

Hydraulic fracturing techniques have been refined through years of development in othershale gas plays, notably the in Barnett Shale in Texas. Most enhancements have focusedon the nature of the frac additives and the propping agents such as fine sand or ceramicmaterial employed in the fracing process.

Today, well stimulation in the MarcellusFormation in Pennsylvania is a highly specialized operation that utilizes computersimulation/modeling to design the fracing process, develop specifications on the volumes of fluidand proppant to use, calculate the pressure required, and determine the composition of the fracingfluid.This data is integrated with lithologic and othercharacteristics unique to the formation, such as depth, temperature and thermal maturity,and the structural characteristics of the shale. Collectively, these aspects are used todetermine the fracability of the formation.

Horizontal well drilling and completion is another technology used in the Marcellus

Formation to increase the productivity of a gas well by maximizing the length of thewellbore through the target formation. Current drilling practices in the Marcellus shale inPennsylvania utilize both horizontal and the more traditional vertical wells. While avertical well may be exposed to as little as 50 feet of the formation, horizontal wells maybe developed with a lateral borehole extending a length of 2,000 feet to more than 6,000


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feet into the target formation. Vertical wells require less capital investment compared to ahorizontal well, but are less productive than a horizontal well. Regardless of thecompletion technique, however, both vertical wells and horizontal wells completed in thetight gas formations such as the Marcellus usually require some type of formationstimulation such as hydraulic fracturing.

When drilling a well into the Marcellus shale or another oil and gas-bearing formation, aninitial string of drive pipe, or conductor pipe, is installed to prevent unconsolidated

materials such as soil, sand and gravel from caving in during well drilling.Next, asurface string, or casing smaller in diameter than the conductor pipe, is installed afterdrilling below the entire vertical length of fresh groundwater. This casing string must beproperly cemented to the surface to protect all potable groundwater sources fromproduction-related activity in the wellbore that is drilled and completed to the targetformation. If coal is present, another string of casing will be installed to isolate thisinterval. An intermediate casing string may also be installed under certain conditions toisolate, stabilize or provide well control to a greater depth than that provided by thesurface casing or coal protection casing. Each casing string will be deeper, butsuccessively smaller in diameter. As mentioned above, the annular space between theborehole and each casing string is typically cemented to the surface or to a prescribedheight above the bottom of the casing string, to ensure isolation and protection of eachzone.

Finally, a production interval is drilled, which may be several tens of feet to several

hundred feet in a vertical Marcellus well, or up to several thousand feet in a horizontal

well. This zone typically is electronically analyzed or logged by a company that

specializes in this service, and is achieved by lowering an electronic device on a wireline

into the wellbore, where data on porosity, density and other characteristics are analyzed

to determine the production potential of the formation. After the well has been logged,

the production casing is installed in the borehole and cemented to isolate these zones.

Each interval isolated in a fracing operation, whether a vertical well or a horizontal well,

is subject to a specific sequence of fluid additives, each with its own engineered purpose

to facilitate the production of gas from the well. Hydraulic fracturing of Marcellus wells

in Pennsylvania typically utilizes a water-based fluid known as slickwater frac.

Slickwater fracs are predominantly water, pumped at high pressure, with lesser amounts

of sand, along with very dilute concentrations of certain additives and chemicals designed

to stimulate the formation, enhance the return, or flowback of the slickwater solution

following well stimulation, and increase the production of gas from the reservoir. The

particular chemistry of the frac fluid may vary from site to site.

The term slickwater refers to friction-reducing agents, such as potassium chloride,polyacrylamide or other chemicals, added to the water to reduce the pressure needed topump the fluid in the wellbore. These additives may reduce tubular friction in the


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wellbore by 50 to 60%.The sequence of additives in fracing a particular interval typically consists of:1. An acid stage, consisting of several thousand gallons of water mixed with a diluteacid, such as hydrochloric or muriatic acid. This serves to clear cement debris inthe wellbore and provide an open conduit for other frac fluids, by dissolvingcarbonate minerals and opening fractures near the wellbore.2. Apad stage, consisting of approximately 100,000 gallons of slickwater withoutproppant material. The slickwater pad stage fills the wellbore with the slickwatersolution (described below), opens the formation and helps to facilitate the flowand placement of proppant material.3. Aprop sequence stage, which may consist of several substages of watercombined with proppant material, which consists of a fine mesh sand or ceramicmaterial, intended to keep open, or prop the fractures created and/or enhancedduring the fracing operation after the pressure is reduced. This stage maycollectively use several hundred thousand gallons of water. Proppant materialmay vary from a finer particle size to a coarser particle size throughout thissequence.4. A flushing stage, consisting of a volume of fresh water sufficient to flush the

excess proppant from the wellbore.Other additives commonly used in the fracing solution employed in Marcellus wellsinclude:A dilute acid solution, as described in the first stage, used during the initial fracsequence. This cleans out cement and debris around the perforations to facilitatethe subsequent slickwater solutions employed in fracturing the formation;A biocide or disinfectant, used to prevent the growth of bacteria in the well thatmay interfere with the fracing operation. Biocides typically consist of brominebasedsolutions or glutaraldehyde.

A scale inhibitor, such as ethylene glycol, used to control the precipitation of

certain carbonate and sulfate minerals;Iron control/stabilizing agents such as citric acid or hydrochloric acid, used toinhibit precipitation of iron compounds by keeping them in a soluble form;Friction reducing agents, also described above, such as potassium chloride orpolyacrylamide-based compounds, used to reduce tubular friction andsubsequently reduce the pressure needed to pump fluid into the wellbore. Theadditives may reduce tubular friction by 50 to 60%. These friction-reducingcompounds represent the slickwater component of the fracing solution.Corrosion inhibitors, such as N,n-dimethyl formamide, and oxygen scavengers,such as ammonium bisulfite, are used to prevent degradation of the steel wellcasing.Gelling agents, such as guar gum (a common food additive), may be used in smallamounts to thicken the water-based solution to help transport the proppantmaterial.Occasionally, a cross-linking agentwill be used to enhance the characteristics andability of the gelling agent to transport the proppant material. These compoundsmay contain boric acid or ethylene glycol. When cross-linking additives areadded, a breaker solution is commonly added later in the frac stage, to cause theenhanced gelling agent to break down into a simpler fluid so it can be readilyremoved from the wellbore without carrying back the sand/proppant material.

The additives mentioned above are relatively-common components of a water-based fracsolution used in tight gas formations such as the Marcellus Shale in Pennsylvania.However, it is important to note that not all of the additives listed here are used in everyhydrofracturing operation; the exact blend and proportions of additives will vary basedon the site-specific depth, thickness and other characteristics of the target formation.


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Nitrogen-based frac solutions are also occasionally used to stimulate shale gas plays.These foam fracs typically require only 25 % of the water demand needed for aslickwater frac. However, these nitrogen-based foam fracs are effective only informations that reside at relatively shallow depths.


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Procesul de

fracturare/ fisurare hidraulic

Accesarea

rezervorului

de gaze

Presiunea apei

creaz o fisur

Fisurare calculat i

controlat cu precizie

Producia de gaze din

ist

Diagrama schematic

aunei fisurri

articol mpg mai 2013

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