drilling technology and hydraulic fracturing shale gas group b3 (part2)

7/29/2019 Drilling Technology and Hydraulic Fracturing Shale Gas Group b3 (Part2)

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Report on Drilling

Technology and

Hydraulic Fracturing

in Gas Shales

By Group B3 (Part 2)



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Group Members

NAME ROLL NUMBER

DHWANI SHAH 10BPE155

ANKIT DIWAKAR 10BPE157

NARENDRA SINGH SHEKHAWAT 10BPE167

PARTH BHUT 10BPE168

ANMOL GARG 10BPE169

HARSH JAJAL 10BPE173

TANMAY SONI 10BPE174

GURVEER SINGH 10BPE175

MADHUKAR KUMAR 10BPE176

SAPNA SAHANI 10BPE177

SHASHWAT SHARMA 10BPE179

HARSHIL SARADVA 10BPE181



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Acknowledgement

We would like to thank Dr Bijaya Kumar Behera for providing us the opportunity to do this project

and do some background research for the topic. We would also like to thank Prof SSP Singh for

giving us a brief idea about some of the topics covered in this report.



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Content

SL.NO. TOPIC PAGE NUMBER

INTRODUCTION 5

SUBSURFACE EXPLORATION FOR SHALE GAS 6-10

DRILLING TECHNOLOGY USED 11-16

PROCESS OF FRACTURING 17

ROCK MECHANICS OF FRACTURING 17-22

ROLE OF FRACTURING FLUID 23-25

ROLE OF PROPPANTS 25-28

ENVIRONMENTAL CHALLENGES 29-32

CONCLUSION 33

BIBLIOGRAPHY 34



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Introduction

Shale gas is natural gas that is produced from a type of sedimentary rock derived from clastic

sources often including mudstones or siltstones, which is known as shale. Clastic sedimentary

rocks are composed of fragments (clasts) of pre-existing rocks that have been eroded,

transported, deposited and lithified (hardened) into new rocks. Shale contains organic

material which was lain down along with the rock fragments. In areas where conventional

resource plays are located, shale can be found in the underlying rock strata and can be the

source of the hydrocarbons that have migrated upwards into the reservoir rock. Shale contains

organic matter (kerogen) which is the source material for all hydrocarbon resources. Over

time, as the rock matures, hydrocarbons are produced from the kerogen. These may then

migrate, as either a liquid or a gas, through existing fissures and fractures in the rock untilthey reach the earth‘s surface or until they become trapped by strata of impermeable rock.

Porous areas beneath these ‗traps‘ collect the hydrocarbons in a conventional reservoir,

frequently of sandstone.

Shale gas resource plays differ from conventional gas plays in that the shale acts as both the

source for the gas, and also the zone (also known as the reservoir) in which the gas is trapped.

The very low permeability of the rock causes the rock to trap the gas and prevent it from

migrating towards the surface. The gas can be held in natural fractures or pore spaces, or can

be adsorbed onto organic material. Aside from permeability, the key properties of shale,

when considering gas potential, are total organic content (―TOC‖) and thermal maturity. TOC

is the total amount of organic material (kerogen) present in the rock, expressed as a

percentage by weight. Generally, higher the TOC, the better is the potential for hydrocarbon

generation. The thermal maturity of the rock is a measure of the degree to which organic

matter contained in the rock has been heated over time, and potentially converted into liquid

and/or gaseous hydrocarbons. Thermal maturity is measured using vitrinite reflectance (Ro).

Because of the special techniques required for extraction, shale gas can be more expensive

than conventional gas to extract. On the other hand, the in-place gas resource can be very

large given the significant lateral extent and thickness of many shale formations. However,

only a small portion of the world‘s shale gas is theoretically producible and even less likely to

be producible in a commercially viable manner. Therefore a key determinant of the success

of a shale play is whether, and how much, gas can be recovered to surface and at what cost.



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Subsurface Exploration for Shale Gas

Subsurface exploration begins with a license awarded for a defined period of time. But this is only the

first step in the lengthy process that may potentially lead to production. Several years of preliminary

surveys and studies, divided into three successive phases, are needed.

Intended to determine whether a play has commercial potential, subsurface exploration lasts five or

six years. The purpose of this phase is to determine both the size of the deposit and the composition

of the source rock. These factors have a decisive impact on the technical and economic feasibility of

any future production.

Phase 1: Locating Reserves

To determine whether a region has reserve potential, the source rock and the characteristics of the

subsurface geology must be studied. This preliminary phase lasts one-and-half to two years. It is

based on analyses of various samples and data: source rock samples taken from outcrops, core

samples taken from the subsurface and existing data such as core data, seismic data and drilling

cuttings from earlier boreholes. Based on these analyses, it is possible to estimate:

The thickness of the source rock.

Its area.

Its mineral composition, particularly the proportion of clay.

The first two of these factors indicate the dimensions of the reservoir, while the third affects how the

rock will respond to fracturing.

Figure 1

http://www.total.com/en/popin-grand-format-en-922859.html&img=/MEDIAS/MEDIAS_INFOS/4579/EN/LocalisationSousSol-EN-L.jpg



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If the dimensions and geological characteristics of the reservoir appear promising, a second phase of

exploration is undertaken to estimate the amount of gas in place in the source rock.

Phase 2: Appraising the Amount of Recoverable Gas

This phase also lasts from half-and-a-half to two years and marks the start of the operational phase of

work. Its purpose is to acquire more detailed data to characterize and the reservoir and apparaise the

gas in place.

Phase 2 focuses on drilling at least one or two conventional vertical wells down to the source rock.

The core samples taken from these boreholes are used to precisely measure rock parameters such

as porosity and permeability. It is essential to know these parameters because:

The less porous the rock and the smaller the pores (the spaces between the grains of the rock), the

less hydrocarbons the rock can hold.

The less permeable the rock (in other words, the less interconnected the pores), the less its fluids can

circulate within.

Other steps include performing fracturing tests on the samples. Phase 2 thus serves to target the most

promising plays in terms of the volume of gas in place and potential extraction. Only the most

promising plays will be graduate to the next phase.

Phase 3: Estimating the Profitability of the Play

This final phase of the process (one to two years) aims to assess the profitability of the play and how

it can be developed, in line with the environmental and CSR assessments previously conducted.

The first step is in situ fracturing tests on at least one or two vertical boreholes in order to study how

the source rock will crack under these conditions. The wells drilled during the previous phase are

usually reused, but it may be useful to drill more to better understand and delineate the area

containing the reserves. Additional seismic surveys may also be conducted.

In situ tests also make it possible to develop the most appropriate techniques, because every drilling

area has its own specific features.

Well production tests take place over several weeks, to study the technical behaviour of the wells and

their profitability.

If the results are encouraging, the following steps take place:

Drilling of horizontal wells to tap s sufficient area of the reservoir.

Hydraulic fracturing of the source rock.

Monitoring of well productivity for a few weeks.

An economic feasibility study incorporating the results of production tests and technical,

environmental and social requirements



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Only after all these analyses have been performed is a decision made on whether to proceed

with development and operation.

Resource Assessment of Shale Gas Basin

Preliminary geological and reservoir data are assembled for each major shale formation, including the

following key items:

Depositional environment of shale (marine vs. non-marine)

Depth (to top and base of shale interval)

Structure, including major faults

Gross shale interval

Organically-rich gross and net shale thickness

Total organic content (TOC, by wt.)

Thermal maturity (Ro)

These geologic and reservoir properties are used to provide a first order overview of the geologic

characteristics of the major shale gas formations and to help select the shale gas formations deemed

worthy of more intensive assessment.

Establishing the Areal Extent of Major Shale Gas Formations.

Having identified the major shale gas formations, the next step is to undertake more intensive study to

define the areal extent for each of these formations. For this, the study team searches the technical

literature for regional as well as detailed, local cross-sections identifying the shale gas formations of

interest. In addition, the study team draws on internal cross-sections previously prepared by Advanced

Resources and, where necessary, assembles well data to construct new cross-sections. The regional

cross-sections are used to define the lateral extent of the shale formation in the basin and/or to identify

the regional depth and gross interval of the shale formation. Defining the Prospective Area for Each

Shale Gas Formation .An important and challenging resource assessment step is to establish the

portions of the basin that, in our view, are deemed to be prospective for development of shale gas. The

criteria used for establishing the prospective area include:

Depositional Environment.

An important criterion is the depositional environment of the shale, particularly whether it is marine

or non-marine. Marine-deposited shales tend to have lower clay content and tend to be high in brittle

minerals such as quartz, feldspar and carbonates. Brittle shales respond favorably to hydraulic



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stimulation. Shales deposited in non-marine settings (lacustrine, fluvial) tend to be higher in clay,

more ductile and less responsive to hydraulic stimulation.

Figure 2

Depth

The depth criterion for the prospective area is greater than 1,000 meters, but less than 5,000 meters

(3,300 feet to 16,500 feet). Areas shallower than 1,000 meters have lower pressure and a lower gas

concentration. In addition, shallow shale gas formations have risks of higher water content in their

natural fracture systems. Areas deeper than 5,000 m have risks of reduced permeability and much

higher drilling and development costs.

Total Organic Content (TOC)

Organic materials such as microorganism fossils and plant matter provide the requisite carbon,

oxygen and hydrogen atoms needed to create natural gas and oil. As such TOC is an important

measure of the gas generation potential of a shale formation. In general, the TOC of prospective area

needs to be equal to or greater than 2%.

Thermal Maturity

The thermal maturity of the prospective area needs to have a Ro greater than 1.0%, with a second

higher quality prospective area defined as having a Ro greater than 1.3%. Higher thermal maturity



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settings also lead to the presence of nanopores which contribute to additional porosity in the shale

matrix. Figure 2.7 provides an illustration of the relationship between thermal maturity and the

development of nanopores in the shale matrix.. Thermal maturity measures the degree to which a

formation has been exposed to high heat needed to break down organic matter into hydrocarbons.

The reflectance of certain types of minerals (Ro %) is used as an indication of Thermal Maturity.

Geographic Location.

The prospective area is limited to the onshore portion of the shale gas basin.

Figure 3



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Drilling Technology Used In Drilling In Shale Reservoirs

New drilling techniques have increased the amount of gas that's accessible, but whether it's truly

recoverable may hinge on whether concerns about water are addressed convincingly. Recovery of

shale gas requires large quantities of water, which is injected to break up deep rock formations.Thequality of water injected plays a prominent role too.

Horizontal drilling and hydraulic fracturing have been the two most convergent technologies that has

been showing the abilities of recovering the shale gas.

Horizontal Drilling

It‘s the horizontal drilling that has been the truly disruptive innovation. Once a well is sunk about 2-3

kilometres into the ground, advanced computer controls now make it possible to gradually turn the bit

and guide it horizontally for 10 km or more to within centi-meters of target spots. This sideways

drilling makes it possible to access much more gas from a single hole, thereby improving the

economics. At least equally important is that sidling in sharply reduces the surface footprint

associated with lifting a given quantity of gas, which makes the whole process much more palatable to

denizens of the drilling area.

To stimulate the productivity of wells in organic-rich shales, companies drill horizontally through the

rock unit and then use hydraulic fracturing to produce artificial permeability that is propped open

by frac sand. Done together, horizontal drilling and hydraulic fracturing can make a productive well

where a vertical well would have produced only a small amount of gas . Horizontal drilling in

combination with hydraulic fracturing was first done on a large scale during the last decade in the

Barnett Shale formation in the Bend Arch – Fort Worth Basin, in Texas, where the techniques proved

highly successful. Now they are being transferred to the Marcellus Shale, a gigantic geological

formation under virtually all of Pennsylvania and much of upstate New York, with flanks stretching

into West Virginia andOhio.

Drilling methodology

Most horizontal wells begin at the surface as a vertical well. Drilling progresses until the drill bit is a

few hundred feet above the target rock unit. At that point the pipe is pulled from the well and a

hydraulic motor is attached between the drill bit and the drill pipe.

The hydraulic motor is powered by a flow of drilling mud down the drill pipe. It can rotate the drill bit



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without rotating the entire length of drill pipe between the bit and the surface. This allows the bit to

drill a path that deviates from the orientation of the drill pipe.

After the motor is installed the bit and pipe are lowered back down the well and the bit drills a path

that steers the well bore from vertical to horizontal over a distance of a few hundred feet. Once the

well has been steered to the proper angle, straight-ahead drilling resumes and the well follows the

target rock unit. Keeping the well in a thin rock unit requires careful navigation. Downhole

instruments are used determine the azimuth and orientation of the drilling. This information is used to

steer the drill bit.

Horizontal drilling is expensive. When combined with hydraulic fracturing a well can cost up to three

times as much per foot as drilling a vertical well. The extra cost is usually recovered by increased

production from the well. These methods can multiply the yield of natural gas or oil from a well.

Many profitable wells would be failures without these methods.



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Figure 4

Drilling multiple horizontal well from centralized well pads for Marcelleus Shale.

The Marcellus Shale is the newest ―play‖ in gas drilling in West Virginia and other states in the

East. It is different from other plays in that it produces much more gas, and is under much more area

(as explained below) than previous plays. It could be the biggest play in West Virginia‘s history. But



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it has much more adverse effect on surface land owners and others in West Virginia for two

reasons. First, shale wells are drilled much closer together, and are therefore more densely numerous

on the surface, than traditional plays in ―sands‖. Second, the new drilling and fracturing techniques

that have for the first time made it possible to economically produce gas from the Marcellus Shale

take up much more land and use much more water for ―fracturing‖ the gas bearing formation. Instead

of a well site with a typical drilling rig and a single drilling pit on 1.5 to 3 acres (plus a couple tractor

trailer loads of water for the ―fracture‖ process), a Marcellus Shale vertical well takes a bigger drilling

rig, a bigger drilling pit, and in addition an impoundment pond the size of an Olympic swimming pool

to hold 600,000 to 1 Million gallons of water for the fracturing process – and many more than 100

tractor trailer loads of water and sand.

Until now, almost all gas wells drilled in the East have been drilled vertically, like the one above. The

driller sets up a drilling rig on a well site directly above the place where he wants to penetrate the gas

bearing formation. He drills straight down until he drills though the gas bearing formation, which in

the case of the Marcellus Shale is up to 100 feet thick in West Virginia. He cements production pipe

into the gas bearing formation. He puts holes out of the production pipe into the gas bearing

formation. He fractures the rock in the area around the 100-foot vertical well bore so the gas will

flow out of the formation faster. And he pipes that gas to the surface and to market. This process is

illustrated on the right side of the illustration below.

Figure 5

In horizontal drilling the driller drills down vertically until near the top of the gas bearing formation,

then new technology allows the driller to bend the well bore sideways so that it is horizontal by the

time it penetrates the gas bearing formation. Using pressure from the downward weight of the

horizontal drilling pipe the driller can drill 4000 or 5000 feet sideways, and maybe more, through the

Marcellus Shale. Developing techniques allow the driller to fracture the horizontal well bore in stages

all along its 4000 feet of length – as opposed to fracturing only the 100 feet that a vertical well bore

runs down through the Marcellus Shale here. As you can see in the illustration above, it would take



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four or more vertical wells to drill, fracture and produce the area of the gas bearing formation that can

be produced by only one horizontal well.

Even newer techniques allow the driller to drill 4 or 6 or even 8 horizontal wells from only one well

pad/site. Having 6 or 8 horizontal wells drilled from one pad taking the place of 20 o4 24 verticalwells each on their own well pad/site is a HUGE improvement for surface owners! As illustrated

below, one horizontal well pad/site (see the yellow square below) with six wells horizontal wells

drilled from it (see the yellow lines below) can take the place of 24 vertical wells pads/sites (the

purple squares below).

Figure 6

So with horizontal drilling there is 1 well pad/site with one access road and one drilling pit and one

frac water impoundment pond instead of 24 five-acre, vertical well pads/sites, and 24 access roads and

24 drilling pits and multiple frac water impoundments. (Note that the vertical wells in this illustration

are spaced 1000 feet apart. Most Marcellus Shale wells in West Virginia are being spaced 1500 feet

apart. So these 6 horizontal wells might not replace quite as many vertical wells as the image

illustrates. But the point is the same. And the drillers are now drilling 8 wells from one well pad

instead of the 6 in the illustration)

Advantage Of This Technique.



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Not only is horizontal drilling of multiple Marcellus Shale gas wells from centralized well pads/sites

better for surface owners, it is better for lots of other people and interests:

It is less risk to ground water if there are only 6 penetrations in one place from the 6 or 8

wells on the centralized pad instead of 24 all over the place.

It lessens the dangers of other environmental concerns because there is less forest

fragmentation, less inevitable steam siltation from more access roads (and horizontal well

access roads tend to be better constructed and maintained than vertical well access roads) etc.

etc.

It is better for coal owners and coal companies and coal miners. This is because the

horizontal well driller goes through the coal seams while the well bore is still being drilled

vertically. So 6 or 8 well bores are drilled through one spot in the horizontal coal seam, rather

than drilling 24 vertical bores drilled all through the coal seam. Since the well bores are

drilled in one spot, there is less risk to the safety of miners of running into one as they mine

through the coal seam. Because coal companies have to leave a circle of unmined coal

around every gas well bore in order to protect miners, having 24 well bores spread out all

through the coal seam would ―sterilize‖ large quantities of coal from being mined.

Investors in oil and gas drilling probably also are benefitted. Although the initial capital cost

of a horizontal well is greater, they get out more gas faster and cheaper than vertical wells and

so save production costs in the long run.



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Fracturing

Process

Hydraulic fracturing, commonly referred to as fracking, is the process of creating fissures, or

fractures, in underground formations to allow natural gas to flow. In deep shale gas plays, water, sand

and other additives are pumped under high pressure into the formation to create fractures. The fluid is

more than 99% water and sand, along with a small amount of special-purpose additives. The newly

created fractures are ―propped‖ open by the sand, which allows the natural gas to flow into the

wellbore and be collected at the surface. Normally a hydraulic fracturing operation is only performed

once in the life of a well. Variables such as surrounding rock formations and thickness of the targeted

shale formation are studied by scientists before hydraulic fracturing is conducted. The result is a

highly sophisticated process that optimizes the network of fractures and keeps them safely contained

within the boundaries of the deep shale gas formation.

Process of Hydraulic Fracturing

The following steps are involved in the process of Hydro Fracturing:-

1.) A fracturing treatment operation begins by rigging up a high pressure steel treating or flow

line from special high-pressure fracturing pumps to the well and pressure-testing the

equipment for safety.

2.)

The next step is to inject a large volume of special fluid(s) into a prospective producing

formation at an injection rate that will place sufficient stress on the rock to cause the rock to

physically split (fracture) in one or more places. This initial volume of fluid is termed the

―Pad‖ and typically comprises 20% of total fluid volume.

3.) The Pad fluid is pumped to create enough fracture width to accept proppant particles.

4.) Proppant is typically comprised of size-graded, rounded and nearly spherical white sand, but

may also be man-made particles



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Rock Mechanics in Hydraulic Fracturing

- A theoretical examination of the mechanisms of hydraulic fracturing of rocks led to

the conclusion that, regardless of whether the fracturing fluid was penetrating, the

fractures produced should be approximately perpendicular to the axis of minimum

principal stress.

- The state of stress, and hence the fracture orientations, is governed by ―incipient

failure‖ (i.e., faulting) of the rock mass.

- In areas subject to active normal faulting, fractures should be approximately vertical.

- In areas subject to active thrust faulting, fractures should be approximately horizontal.

Influence of Pore Pressure

Pore fluids in the reservoir rock play an important role because they support a portion of the

total applied stress. Hence, only a portion of the total stress, namely, the effective stress

component, is carried by the rock matrix. In addition, the mechanical behaviour of the porous

rock modifies the fluid response. Two basic mechanisms highlight this coupled behaviour:

An increase of pore pressure induces rock dilation.

Compression of the rock produces a pore pressure increase if the fluid is prevented from

escaping from the porous network.

Where σ is the total applied stress, σ´ is the effective stress governing consolidation of the

material, and p is the pore pressure.

Fracture Mechanics

Griffith‘s original treatment expressed the condition that the total energy is unchanged by

small variations in the crack length. The different approach presented here states that the

energy that is consumed by the creation of new surfaces should be balanced by the change in

the potential energy of the system:



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Where dWelas represents the change in elastic energy stored in the solid, dWext is the change

in potential energy of exterior forces, dWs is the energy dissipated during the propagation of

a crack, and dWkin is the change in kinetic energy. Energy dissipated as heat is neglected.

Where γ F is the fracture surface energy of the solid, which is the energy per unit area

required to create new fracture surfaces (similar to the surface tension of a fluid ).

The propagation is unstable if the kinetic energy increases; thus, dWkin> 0 gives

where the strain energy release rate Ge is defined as

The onset of crack propagation, which is referred to as the Griffith criterion, is

Irwin’s Approach

Irwin‘s approach is similar to Griffith‘s. It can be demonstrated that, for an isotropic and

linear elastic material, the stress intensity factor is related to the strain energy release rate by

As an example of this application to hydraulic fracturing, the stress intensity factor for a

uniformly pressurized crack subjected to a far-field minimum stress σ3 is

Where pf is the pressure in the crack, L is the half-length of the crack, and plane strain is

assumed. During propagation, the net pressure (pf – σ3) is therefore



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Kic is critical stress intensity factor

Stress- Strain Curve

Figure 7

Stress-strain curves (Michael J Economide, Kenneth G. Nolte, “Reservoir

Stimulation”, Wiley John L. Gidley)

During the initial stages of loading, from O to point A, the rock stiffens. This nonlinear

regime is probably due to the closing of preexisting micro cracks pervading the specimen.

This particular region of the stress-strain curve is a signature of the stress history under- gone

by the rock specimen during past geologic time, including the coring process.

As the load increases further, the stress-strain curve becomes linear (from point A to point B);

this is the portion of the stress-strain curve where the rock behavior is nearly elastic. If

unloading occurs in this region, the strain returns almost to zero, usually along a different

path. This effect is called hysteresis and indicates that some energy dissipates during a cycle

of loading and unloading.

When the rock specimen is loaded beyond point B, irreversible damage sets in. It is shown by

a decrease of the slope of the stress versus radial strain curve. At this stage, the damage is not

seen on the axial strain. At point C, the axial strain also becomes nonlinear, and large

deformations eventually occur. If the rock is unloaded in this region, permanent strains at

zero stress are observed. Point D is the maximum load that the rock can sustain under a given

confining pressure.



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Rock failure (i.e., when the sample loses its integrity) occurs at about this point. Some rocks,

especially those with high porosity, may not exhibit a maximum peak stress but continue to

carry increasing stress (i.e., continue to harden)

Brittle Fracture

Exhibits little or no plastic deformation and low energy absorption before failure.

- Crack propagation spontaneous and rapid. Occurs perpendicular to the direction of the

applied stress, forming an almost flat fracture surface

- Deemed unstable as it will continue to grow without the aid of additional stresses.

Crack propagation across grain boundaries is known as transgranular, while propagationalong grain boundaries is termed intergranular.

Cartoon of simulated brittle fracture

Crack Initiation and Propagation

Cracks usually initiate at some point of stress concentration

-

Common areas include scratches, fillets, threads, and dents

Propagation occurs in two stages: - Stage I: propagates very slowly along crystallographic planes of high shear stress and

may constitute either a large or small fraction of the fatigue life of a specimen

- Stage II: the crack growth rate increases and changes direction, moving perpendicular

to the applied stress.

Figure 8



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Fracture Mechanics

Uses fracture analysis to determine the critical stress at which a crack will propagate and

eventually fail.

The stress at which fracture occurs in a material is termed fracture strength

- For a brittle elastic solid this strength is estimated to be around E/10, E being the

modulus of elasticity

- This strength is a function of the cohesive forces between the atoms

-

Experimental values lie between 10 and 1000 times below this value

These values are a due to very small flaws occurring throughout the material referred to as

stress raisers.

If we assume that the crack is elliptical in shape and it’s longer axis perpendicular to the

applied stress, the maximum stress at the crack tip is:

Fracture will occur when the stress level exceeds this maximum value.



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Role of fracturing fluid

Composition of the Fracturing Fluid

1.) Base Fluid : Water

To create a network of fractures in the Shale and carry Proppant to the formation.2.) Proppant : Sand

Allows the fractures to remain open so the gas can escape.

3.) Surfactant or gellant : Isopropanol, Trimethyloctadecylammonium, Sodium Xylene

Suphonate

Used to reduce the surface tension of the fracturing fluids to improve liquid recovery

from the well after the frac.

4.) Diluted Acid : Hydrochloric Acid (HCl)

Help to dissolve cement and minerals and initiate fractures

5.) Friction reducer : Polyacrylamide

Reduces friction between the fluid and pipe.

6.) Anti-microbial agents : Glutaraldehyde, ethanol, and methanol

Eliminates bacteria in the water that produces corrosive by-products.

7.) Scale Inhibitor : Ethylene glycol, alcohol , and sodium hydroxide

Prevents scale deposit in the pipe.

8.) Breaker : Sodium Hypochlorite

Breaks down the gelling agent to allow water and sand to flow more easily in and out

the fractures.

9.) Clay control : Quaternary Amine

Prevents clay swelling and clay migration.

10.) Iron control : Trisodium Nitrilotriacetate

Prevents precipitation of metal oxides

11.) De-emulsifier : Isopropanol

Used to break emulsions (water-in-oil or vice-versa)12.) Corrosion Inhibitor : Methanol

Prevents carbonate and sulfate scale precipitation in fracturing systems.

13.) Foam Preventor : Tri-Butyl Phosphate

Reduces viscosity and mud weight.

14.) Crosslinker : Borate salts

Maintains fluid viscosity as the temperature increases

15.) pH adjusting agents : Sodium or potassium carbonate

Maintains the effectiveness of the other components such as crosslinkers.



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The hydraulic fracturing process has been used commercially as a means of stimulating oil and gas

production for over 40years. In the application of this process, a viscous

Non-Newtonian fluid containing a high proppant concentration is injected down the wellbore at high

rate and pressure to create and extend a fracture system in the formation of interest. Fracturing fluids

are generally in turbulent flow in the wellbore and perforations and in laminar flow in the fracture

system. Characterization of the hydraulic and rheological properties of these fluids in both laminar

and turbulent flow regimes is important for the successful application of this process.

TYPES OF FRACTURING FLUIDS

Since the advent of fracturing fluids in hydraulic fracturing in 1949, fracturing fluid chemistry has

advanced significantly. Today, various types of fracturing fluids are available for reservoirs ranging

from shallow, low temperature formations to those that are deep and hot. Table1lists the most

commonly used fracturing fluid systems in the oil and gas industry.

Water Base

Water base fracturing fluids have been widely used in oil and gas producing wells because of their

low cost, high performance and ease of handling. Many types of water soluble polymers such as guar

gum, hydroxypolypropyl guar (HPG),carboxymethylhydroxypropylguar(CMHPG) andhydroxyethyl

Cellulose (HEC) can be added to water to make it more viscous to improve proppant transport

properties. At higher temperature, various types of cross linkers are used to offset the decrease in

viscosity because of the thermal effect and therefore expand the range of temperature application. The

most popular crosslinkers are metal ions such as borate, Ti(IV), Zr(IV),and AI(III).

Potential problems associated with the water base fluid systems are: formation damage of water

sensitive zones, loss of fracture conductivity due to residue, unbroken gel, and filter cakes. Many

special chemical additives, however, have been developed to make the water base fluid systems

adaptable to formations that maybe adversely affected by water. Breakers are also incorporated to

break the gel fluid at the desired time after treatment so a treated well can be operated again with

minimum delay. Addition of fluid loss additive can enhance the fluid loss control of the water base

fluid systems.Oil Base

Oil base fracturing fluids are primarily for water sensitive formations known to suffer permeability

reduction when exposed to aqueous fluids. Oil base fluids normally employ gelled kerosene, diesel,

distillates and many crude oils. Aluminium salts of organic phosphoric acids are generally used to

raise viscosity, improve temperature stability and proppant carrying capability. Compared to water

base fluids, they are more expensive and more difficult to handle. Oil-base fluids are also more

hazardous because of flammability.



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Emulsions

Polymer oil-in-water emulsions normally consist of 60 to 70% liquid hydrocarbon as an internal phase

and 30 to 40% gelled water as the external phase. The hydrocarbon may be diesel, kerosene or crude

oil while the aqueous phase maybe gelled fresh water, potassium chloride solution, or some acid

solutions. The emulsions generally provide excellent fluid loss control, less formation damage and

good proppant transport properties. However they are difficult to prepare and somewhat costly.

Alcohol Base

Alcohol base fracturing fluids are specially developed for treating gas producing formations. A gelled

methanol water solution has high solubility in produced gas, excellent viscosity, miscibility with

formation waters, and low surface tension. High vapour pressure and low surface tension permit more

rapid and complete removal of the treating fluid following the treatment even in low permeability,

low pressure formations.

Gas Energized Fluids

Gas energized fluids have steadily increased in usage in fracturing treatments because of their

advantages in reducing proppant and formation damage as well as clean-up cost. Gas energized fluids

usually exhibit very good post-fracture clean up performance when used in low-pressure reservoirs.

Gas energized fluids are generally formed when gas (typically 10to70% carbon dioxide or nitrogen) is

dispersed as small bubbles throughout a continuous liquid phase. The liquid phase typically contains a

surfactant or other stabilizers to reduce phase separation. The liquid phase may be water, water-

methanol mixtures, gelled water, or gelled oils. The inability to measure rheological properties of

these gas energized fluids accurately makes on site quality control and pressure analysis difficult.

Role of Proppants

Proppants are sized particles which are mixed with drilling fluids which keep the fractures open after

the hydraulic treatment. In addition to naturally occurring sand grains,man-made or speciallyengineered proppants,such as resin-coated sand or high strength ceramic materials like sintered

bauxite,may also be used.Proppant materials are carefully sorted for size and sphericity to provide

efficient conduit for production of the fluid from the reservoir to the wellbore.



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Types of Proppant-

Figure 9

Fracturing proppant selection is crucial to optimizing well productivity. Proppants selections arebased upon following considerations-

Sizing-Larger proppant provide greater permeability but are more difficult to place. Larger

proppants create larger area for flow. Ideally perforation diameter should be six times larger

than the proppant diameter. Also the hydraulic fracture width should be three times larger

than the proppant diameter. The rate of settling is proportional to the (diameter)2.

Proppant Strength-Fracturing of deeper formations requires the use of stronger proppant

materials. Sintered bauxite, the first ceramic proppant, contains corundum, one of the hardest

materials known. As a result, it has application in the deepest of wells. Light weight ceramic

(LWC) proppants have a large mullite component, another hard alumina-silicate material.

Also, when ceramic proppants fail, they do not shatter in the same manner as a sand proppant,

but instead cleave into discrete shards still capable of providing significant conductivity



27

Proppant density-The bulk density describes the mass of proppant that fills a unit volume, and

includes both proppant and porosity void volume. The Appearant Specific Gravity(ASG)

represents the apparent density of a single pellet and although it does include any internal

porosity of the proppant particle, it excludes the porosity between grains. Generally, the ASG

is used to estimate proppant settling times, while the bulk density is used to estimate

transportation volumes and actual achieved volume of the fracture. Both properties are

measured without closure stress, so the bulk density will increase substantially if the

proppants crush or if pack rearrangement results in loss of porosity.

Proppant type ASG Bulk Density(lb/ft3)

Bulk

Density(g/cm3)Bulk

Density

(g/cm3)

Sand 2.65 105 1.70

Light Weight

Ceramic2.72 96 1.56

Intermediate Strength

Ceramic3.27 115 1.84

Bauxite 3.56 128 2.05

Besides the traditional proppant selection factors of size, strength, and density, there are many

other important factors to consider.

Proppant Fines- Proppant fines generation and the resulting migration in the fracture are

considered to be one of the major contributors to poor treatment results and well performance.

It has been noted by Coulter & Wells that just 5% fines can decrease fracture flow capacity by

as much as 60%. Hexion‘s advanced grain-to-grain bonding technology reduces proppant

fines generation and migration through the proppant pack. The curable resin coating provides

additional strength to individual grains, generates uniform stress distribution throughout the

pack, and encapsulates any loose fines that may occur.



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Proppant pack cyclic stress-During the life of a well, numerous events such as well shut-ins

during workovers, connections to a pipeline or possible shut-ins due to pipeline capacity lead

to cyclic changes in fracture closure stress. Curable resin coated proppants resist these cyclic

stress changes by forming a flexible lattice network that redistributes the stresses through the

proppant pack, reducing individual point loads on each proppant grain. This feature leads to

improved proppant pack integrity and well production.

Effective vs Refrence Conductivity-Traditionally, proppant performance has been measured using

baseline or reference conductivity testing. Effective conductivity is a much more accurate

measurement of downhole proppant performance. Unfortunately, the low flow rates during the

baseline conductivity test do not simulate downhole flow rates. High flow rates downhole can cause

proppant fines to migrate and severely decrease fracture conductivity.

To incorporate the effect of proppant fines, effective conductivity is calculated using the Coulter &

Wells method to derate the published reference conductivity.

Figure 10

Proppant Flowback-Post treatment proppant flowback is a leading cause of well production

decline, equipment damage, and well shut-ins for repairs. Proppant flowback can also cause

loss of near wellbore conductivity and reduced connectivity to the reservoir.



29

Hexion‘s curable resin coated proppants eliminate proppant flowback by forming a

consolidated proppant pack in the fracture. This grain-to-grain bonding occurs under a

combination of reservoir temperature and closure stress. This Stress Bond™ (SB) technology

leads to increased proppant pack integrity and well production compared to uncoated and

precured resin coated proppants.

Environmental Challenges

1. Higher fresh water consumption:

A gas discovery occurred in Northern Michigan, revealing potential natural gas reserves in

the Collingwood Shale at depths of ranging from 5,000 to 10,000 feet. Horizontal drilling and

multi-stage fracking will be used to collect this gas, which is different than the hydraulic

fracturing techniques historically used in Michigan. This drilling is not only deeper, it also

uses substantially more fresh water (millions of gallons rather than up to one hundred

thousand gallons) and chemicals. There are many unknowns with respect to the

environmental and long-term impacts.

In Karoo, South Africa, during periods of low stream flow it may affect water supplies for

municipalities and industries such as power generation, as well as recreation and aquatic life.

It may also require water overland piping from distant sources. An average well requires 3 to

8 million US gallons (11,000 to 30,000 m3) of water, typically within one week.

2. Water table contamination in drinking water:

Incidents of surface and ground water contamination from the fracking process have been

reported in other states. In Pennsylvania, state regulators found that gas drilling using high-

volume fracking has caused contaminated drinking water, polluted surface waters, polluted

air, and contaminated soils.

Errors in gas well construction or spills during transportation can occur and lead to water

contamination. Fluids can spill before they are injected and fluids recovered from fracturing

can contaminate surface waters. Additionally, drilling into these formations can create

pathways by which fluids or natural gas itself can find its way into water supplies, if drillers

are not careful. It should be noted also that the horizontal sections of the wells are not cased in

cement and, therefore, leakage from these sections could represent a significant threat to

ground water.

Another 2011 study identified 632 chemicals used in natural gas operations. Only 353 of

these are well-described in the scientific literature; and of these, more than 75% could affectskin, eyes, respiratory and gastrointestinal systems; roughly 40-50% could affect the brain



30

and nervous, immune and cardiovascular systems and the kidneys; 37% could affect the

endocrine system; and 25% were carcinogens and mutagens. The study indicated possible

long-term health effects that might not appear immediately. The study recommended full

disclosure of all products used, along with extensive air and water monitoring near natural gas

operations; it also recommended that fracking's exemption from regulation under the US Safe

Drinking Water Act be rescinded.

Source: www.geology.com/energy/hydraulic-fracturing-fluids

http://www.geology.com/energy/hydraulic-fracturing-fluids






31

Figure 11

Source: www.shalegaswiki.com/images/thumb/b/b8/FracfluidComp2.jpg/700px-FracfluidComp2.jpg

3. Earthquakes:

Several earthquakes — including a magnitude 4.0 tremor on New Year's Eve — that had

hit Youngstown, Ohio, throughout 2011 are likely linked to a disposal well for injecting

wastewater used in the hydraulic fracturing process, according to seismologists at Columbia

University.

4. Radioactivity

According to a Times report in February 2011, wastewater at 116 of 179 deep gas wells in

Pennsylvania "contained high levels of radiation," but its effect on public drinking water

supplies is unknown because water suppliers are required to conduct tests of radiation "only

sporadically‖. The New York Post stated that the Pennsylvania Department of Environmental

Protection reported that all samples it took from seven rivers in November and December

2010 "showed levels at or below the normal naturally occurring background levels of

radioactivity", and "below the federal drinking water standard for Radium 226 and

228.‖However the samples taken by the state at least one river, (the Monongahela, a source of

drinking water for parts of Pittsburgh), were taken upstream from the sewage treatment plants

accepting drilling waste water.

In Pennsylvania, much of the wastewater from hydraulic fracturing operations is processed by

public sewage treatment plants. Many sewage plants say that they are incapable of removing

the radioactive components of this waste, which is often released into major rivers. Industry

http://www.shalegaswiki.com/images/thumb/b/b8/FracfluidComp2.jpg/700px-FracfluidComp2.jpg






32

officials, though, claim that these levels are diluted enough that public health is not

compromised.

5. Others:

Construction equipment emissions, fracking equipment, and unintentional gas leaks are

sources of negative air emissions during the fracking process. Large areas of cleared land and

many miles of roadways can scar the landscape and result in habitat fragmentation. Drilling

operations also involve lights, 24 hours a day, and noise pollution from the initial month of

drilling the well to the continuous noise generated by operation of compressor stations.

6. Air:

In 2008, measured ambient concentrations near drilling sites in Sublette County,

Wyoming were frequently above the National Ambient Air Quality Standards (NAAQS) of

75ppb and have been recorded as high as 125 ppb. A 2011 study for the city of Fort Worth,

Texas, examining air quality around natural gas sites "did not reveal any significant health

threats." In DISH, Texas, elevated levels

of disulphides, benzene, xylenes and naphthalene have been detected in the air, emitted from

the compressor stations. People living near shale gas drilling sites often "complain of

headaches, diarrhea, nosebleeds, dizziness, blackouts, muscle spasms, and other problems."

In 2012, researchers from the Colorado School of Public Health showed that air pollution

caused by fracking may contribute to "acute and chronic health problems" for those living

near drilling sites.



33

Conclusion

As a source of abundant, high-quality natural gas, the potential of U.S. shale gas has only

begun to be realized. While the challenges to producers may be significant — and

significantly different from play to play — they are not insurmountable, providing the

right technology and experience are on hand.While conventional horizontal directional

drilling technologies have been used to drill shale gas wells, in almost every case, the rock

around the wellbore must be hydraulically fractured before the well can produce significant

amounts of gas, and the cost of fracturing horizontal wells can be as much as 25 percent of the

total cost of the well. To keep development costs under control, there will be a need for

improved exploration, production efficiencies and best practices that combine current

knowledge and new approaches. In most cases, multiwell drilling can afford improved

efficiencies in hydraulic frac stimulation operations, enhancing the percentage of recoverable

gas to boost production rates over the economic threshold, while pad drilling of several

multilateral wells from a single pad will further improve the economies-of-scale and help

reduce location costs while generating a minimal environmental footprint.



Bibliography

1. World Shale Gas Resources:An Initial Assessment of 14 Regions Outside the United States

by US Energy Information Administration

2.

Shale gas extraction in the UK: A review of hydraulic fracturing June 2012 by The RoyalSociety and The Royal Academy of Engineering

3. Recent Advances in the Fluid Mechanics and Rheology of Fracturing Fluids S.N.Shah,

D.L.Lord,and H.C.Tan, Halliburton Services, SPE,1992

4. Dynamic Rock Mechanics Testing for Optimized Fracture Design by Lacy Lewis L, BJ

Services Company, SPE 1997

5. Proppant Selection and Its Effects on the Results of Fracturing Treatments Performed in Shale

Formations, J.M. Terracina, SPE, J.M. Turner, SPE, D.H. Collins, SPE, and S.E. Spillars,

SPE, Hexion,

6. http://www.energyfromshale.org/shale-extraction-process

7. http://www.halliburton.com/public/solutions/contents/shale/related_docs/H063771.pdf

8. http://www.api.org/policy-and-issues/policy-items/exploration/facts_about_shale_gas.aspx

http://www.energyfromshale.org/shale-extraction-process


http://www.halliburton.com/public/solutions/contents/shale/related_docs/H063771.pdf


http://www.api.org/policy-and-issues/policy-items/exploration/facts_about_shale_gas.aspx





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