**3. Types of fracturing fluids**

*Class Lethal Dose (mg/kg)*

*3* 50 to 500

*4* 500 to 2000

*5* 2000 to 5000

rating. Modified from " www. http://fracfocus.org/chemical-use/what-chemicals-are-used"

*3* Flammable and Combustible Liquids

 Oxidizers and Organic Peroxides Poisonous/Toxic Materials Radioactive Materials Corrosive Materials

*9* Miscellaneous Hazardous Materials

rating. Modified from " www. http://fracfocus.org/chemical-use/what-chemicals-are-used"

**Additional hazard identification resources**

records on over 34,000 wells.

**Table 3.** A summary of the various chemicals used to make Hydraulic Fracturing fluids along with a degree of hazard

http://fracfocus.org/welcome - The Ground Water Protection Council and the Interstate Oil and Gas Compact Commission developed this web site to provide public access to chemicals used in the hydraulic fracturing process and provides a record of the chemicals used in wells in a number of different stated in the United States. At the time of this writing the site had

http://www.osha.gov/chemicaldata/ - This United States Department of Labor website proves a OSHA (Occupational Safety and Health Administration) Occupational Chemical Database

*1* Explosives *2* Compressed Gases

*4* Flammable Solids

\*\* DOT Transportation Hazard Classes

10 Effective and Sustainable Hydraulic Fracturing

*Class*

*5S* 2000 to 5000, an unrestricted self-service product

**Table 2.** A summary of the various chemicals used to make Hydraulic Fracturing fluids along with a degree of hazard

Table 4 provides a qualitative listing of the desirable and undesirable aspects of most fluid systems available today. As one studies the table it is interesting to note that there is "no magic bullet". The qualitative score is close to the same for each fluid and each fluid has its advantages and disadvantages. This means that the final decision is up to the design engineer as to what is best for his reservoir. The different types of fluid systems are outlined below. A description of all the different components used to manufacture the fluids is provided in Side Bar 1.


**Table 4.** Qualitative Fluid Selection Chart

**Water Frac** is composed of water, a clay control agent and a friction reducer. Sometimes a water recovery agent (WRA) is added to try and reduce any relative permeability or water block effects. The main advantage of using a "Water Frac" is the low cost, ease of mixing and ability to recover and reuse the water. The main disadvantage is the low viscosity which results in a narrow fracture width. Because the viscosity is low the main proppant transport mechanism is velocity so water fracs are typically pumped at very high rates (60 to 120 bpm). Fluid loss is controlled by the viscosity of the filtrate which is close to that of water i.e. 1.

Foams made with Nitrogen or Carbon dioxide is generally 65 to 80% (termed 65 to 80 quality) gas in a water carrying media which contains a surfactant based foaming agent. Sometimes

This is done to reduce the amount of water placed on the formation and to provide additional energy to aid in load recover during the post-frac flow back period. Nitrogen can dissipate into the reservoir quite quickly so fluids energized with N2 should be flowed back as soon as

conditions (prior to the well being placed on production), so is less susceptible to dissipation. CO2 does dissolve in crude oil so will act to reduce the crude viscosity which, again, improves

mixture is termed a mist with a "0" viscosity. This quality is normally not used in fracturing. The main disadvantage of these fluids is safety i.e. pumping a gas at high pressure or in the case of polyemulsions and gelled Propane, pumping a flammable fluid. CO2 has an additional hazard in that it can cause dry ice plugs as pressure is reduced. These fluids are generally also

Fluid viscosity for treatment design is determined from laboratory tests and is reported in service company literature. The ideal experiment for describing fluid flow in a fracture would be to shear a fluid between two plates which are moving parallel and relative to one another. The shear stress on the fluid equals the drag force on the plates divided by the area of the plates, and has units of stress or pressure (e.g., psi). The shear rate (or velocity gradient) is the relative velocity of the two plates divided by the separation distance between the plates. Shear rate has the units of 1/time (e.g., sec-1). A vertical 7 ft high by 10 1/3 ft long high pressure parallelplate flow cell, shown in Figure 1, capable of operating to temperatures of 250°F and pressures of 1200 psi is available at the University of Oklahoma11. Termed the "Fracturing Fluid Char‐ acterization Facility (FFCF)" the laboratory simulator is a very sophisticated; one of a kind unit that utilizes 12 servo-controlled 28" by 28" platens that can dynamically adjust the width of

Such an ideal test is not feasible for day to day applications so a rotating "cup and bob" viscometer know as a "Couette" viscometer is used. API standard RP3912 and ISO 13503-113 fully describe the current testing procedures used by the industry. The viscometer uses a rotating cup and a stationary bob with a gap between the two that simulates the fracture. As shown in Figure 2 the rotational speed of the cup imparts a shear rate and the bob measures the shear stress or drag force exerted on the walls of the cup and bob. This is sensed by measuring the torque on the bob. The shear rate is the relative velocity between the stationary bob and the rotating cup divided by the separation gap. Figure 3 shows several commercial rheometers and how they are set up in the field. For a Fann 35 (See Figure 3) equipped with a R1 rotor and a B1 bob and the appropriate spring a rotational speed of 100 RPM represents a shear rate of 170 sec-1 and a speed of 300 RPM gives a shear rate of 511 sec-1. The Fann 35, which is manufactured by the Fann Instrument Company http://www.fann.com/, the Model 3530,

/CO2

more expensive and the gases may not be available in remote areas.

are added at a lower concentration (20 to 30 quality) to form "Energized Fluids".

, under most conditions, is in a dense phase at static down hole

are added is qualities greater than 80 the resulting

Fracturing Fluids

13

http://dx.doi.org/10.5772/56192

N2

or CO2

the fracture is closed. CO2

the slot from 0 to 1.25 inches.

cleanup and rapid recovery. When N2

**4. Chacterization of fracturing fluids**

**Linear Gel** is composed of water, a clay control agent and a gelling agent such as Guar, HPG or HEC. Because these gelling agents are susceptible to bacteria growth a bactericide or biostat is also added. Chemical breakers are also added to reduce damage to the proppant pack. WRA's are also sometimes used. The main advantage of a liner gel is its low cost and improved viscosity characteristics. Fluid loss is controlled by a filter cake which builds on the fracture face as the fluid loses fluid to the formation. The main disadvantage is, as with waterfracs, the low viscosity which results in a narrow fracture width. The main disadvantage when com‐ pared to a waterfrac is that because the returned water has residual breaker the water is not reusable.

**Crosslinked Gels** are composed of the same materials as a linear gel with the addition of a crosslinker which increases the viscosity of the linear gel from less than 50 cps into the 100's or 1000's of cps range. The higher viscosity increases the fracture width so it can accept higher concentrations of proppant, reduces the fluid loss to improve fluid efficiency, improves proppant transport and reduces the friction pressure. This crosslinking also increases the elasticity and proppant transport capability of the fluid. Fluid loss is controlled by a filter cake which builds on the fracture face as the fluid loses fluid to the formation. A full description of the types of crosslinkers used, the chemistry and the mechanism of crosslinking is provided in the companion paper on fracturing fluid components.

**Oil Based Fluids** are used on water-sensitive formations that may experience significant damage from contact with water based fluids. The first frac fluid used to fracture a well used gasoline at the base fluid, Palm Oil as the gelling agent and Naphthenic Acid as the crosslinker i.e. Napalm. Although some crude oils have particulate which could build a filter cake, fluid loss is generally considered to be "Viscosity- Controlled – i.e. C-II". There are some disadvan‐ tages in using gelled oils. Gelling problems can occur when using high viscosity crude oils or crude oils which contain a lot of naturally occurring surfactants. When using refined oils such as diesel the cost is very high and the oil must be collected at the refinery before any additives such as pour point depressants, engine cleaning surfactants etc. are added. Also there are greater concerns regarding personnel safety and environmental impact, as compared to most water-fluids.

**Foam/PolyEmulsions** are fluids that are composed of a material that is not miscible with water. This could be Nitrogen, Carbon dioxide or a hydrocarbon such as Propane, diesel or conden‐ sate. These fluids are very clean, have very good fluid loss control, provide excellent proppant transport and break easily simply via gravity separation. PolyEmulsions are formed by emulsifying a hydrocarbon such as Condensate or Diesel with water such that the hydrocarbon is the external phase. The viscosity is controlled by varying the hydrocarbon/water ratio. Foams made with Nitrogen or Carbon dioxide is generally 65 to 80% (termed 65 to 80 quality) gas in a water carrying media which contains a surfactant based foaming agent. Sometimes N2 or CO2 are added at a lower concentration (20 to 30 quality) to form "Energized Fluids". This is done to reduce the amount of water placed on the formation and to provide additional energy to aid in load recover during the post-frac flow back period. Nitrogen can dissipate into the reservoir quite quickly so fluids energized with N2 should be flowed back as soon as the fracture is closed. CO2 , under most conditions, is in a dense phase at static down hole conditions (prior to the well being placed on production), so is less susceptible to dissipation. CO2 does dissolve in crude oil so will act to reduce the crude viscosity which, again, improves cleanup and rapid recovery. When N2 /CO2 are added is qualities greater than 80 the resulting mixture is termed a mist with a "0" viscosity. This quality is normally not used in fracturing. The main disadvantage of these fluids is safety i.e. pumping a gas at high pressure or in the case of polyemulsions and gelled Propane, pumping a flammable fluid. CO2 has an additional hazard in that it can cause dry ice plugs as pressure is reduced. These fluids are generally also more expensive and the gases may not be available in remote areas.

### **4. Chacterization of fracturing fluids**

**Water Frac** is composed of water, a clay control agent and a friction reducer. Sometimes a water recovery agent (WRA) is added to try and reduce any relative permeability or water block effects. The main advantage of using a "Water Frac" is the low cost, ease of mixing and ability to recover and reuse the water. The main disadvantage is the low viscosity which results in a narrow fracture width. Because the viscosity is low the main proppant transport mechanism is velocity so water fracs are typically pumped at very high rates (60 to 120 bpm). Fluid loss is

**Linear Gel** is composed of water, a clay control agent and a gelling agent such as Guar, HPG or HEC. Because these gelling agents are susceptible to bacteria growth a bactericide or biostat is also added. Chemical breakers are also added to reduce damage to the proppant pack. WRA's are also sometimes used. The main advantage of a liner gel is its low cost and improved viscosity characteristics. Fluid loss is controlled by a filter cake which builds on the fracture face as the fluid loses fluid to the formation. The main disadvantage is, as with waterfracs, the low viscosity which results in a narrow fracture width. The main disadvantage when com‐ pared to a waterfrac is that because the returned water has residual breaker the water is not

**Crosslinked Gels** are composed of the same materials as a linear gel with the addition of a crosslinker which increases the viscosity of the linear gel from less than 50 cps into the 100's or 1000's of cps range. The higher viscosity increases the fracture width so it can accept higher concentrations of proppant, reduces the fluid loss to improve fluid efficiency, improves proppant transport and reduces the friction pressure. This crosslinking also increases the elasticity and proppant transport capability of the fluid. Fluid loss is controlled by a filter cake which builds on the fracture face as the fluid loses fluid to the formation. A full description of the types of crosslinkers used, the chemistry and the mechanism of crosslinking is provided

**Oil Based Fluids** are used on water-sensitive formations that may experience significant damage from contact with water based fluids. The first frac fluid used to fracture a well used gasoline at the base fluid, Palm Oil as the gelling agent and Naphthenic Acid as the crosslinker i.e. Napalm. Although some crude oils have particulate which could build a filter cake, fluid loss is generally considered to be "Viscosity- Controlled – i.e. C-II". There are some disadvan‐ tages in using gelled oils. Gelling problems can occur when using high viscosity crude oils or crude oils which contain a lot of naturally occurring surfactants. When using refined oils such as diesel the cost is very high and the oil must be collected at the refinery before any additives such as pour point depressants, engine cleaning surfactants etc. are added. Also there are greater concerns regarding personnel safety and environmental impact, as compared to most

**Foam/PolyEmulsions** are fluids that are composed of a material that is not miscible with water. This could be Nitrogen, Carbon dioxide or a hydrocarbon such as Propane, diesel or conden‐ sate. These fluids are very clean, have very good fluid loss control, provide excellent proppant transport and break easily simply via gravity separation. PolyEmulsions are formed by emulsifying a hydrocarbon such as Condensate or Diesel with water such that the hydrocarbon is the external phase. The viscosity is controlled by varying the hydrocarbon/water ratio.

controlled by the viscosity of the filtrate which is close to that of water i.e. 1.

in the companion paper on fracturing fluid components.

reusable.

12 Effective and Sustainable Hydraulic Fracturing

water-fluids.

Fluid viscosity for treatment design is determined from laboratory tests and is reported in service company literature. The ideal experiment for describing fluid flow in a fracture would be to shear a fluid between two plates which are moving parallel and relative to one another. The shear stress on the fluid equals the drag force on the plates divided by the area of the plates, and has units of stress or pressure (e.g., psi). The shear rate (or velocity gradient) is the relative velocity of the two plates divided by the separation distance between the plates. Shear rate has the units of 1/time (e.g., sec-1). A vertical 7 ft high by 10 1/3 ft long high pressure parallelplate flow cell, shown in Figure 1, capable of operating to temperatures of 250°F and pressures of 1200 psi is available at the University of Oklahoma11. Termed the "Fracturing Fluid Char‐ acterization Facility (FFCF)" the laboratory simulator is a very sophisticated; one of a kind unit that utilizes 12 servo-controlled 28" by 28" platens that can dynamically adjust the width of the slot from 0 to 1.25 inches.

Such an ideal test is not feasible for day to day applications so a rotating "cup and bob" viscometer know as a "Couette" viscometer is used. API standard RP3912 and ISO 13503-113 fully describe the current testing procedures used by the industry. The viscometer uses a rotating cup and a stationary bob with a gap between the two that simulates the fracture. As shown in Figure 2 the rotational speed of the cup imparts a shear rate and the bob measures the shear stress or drag force exerted on the walls of the cup and bob. This is sensed by measuring the torque on the bob. The shear rate is the relative velocity between the stationary bob and the rotating cup divided by the separation gap. Figure 3 shows several commercial rheometers and how they are set up in the field. For a Fann 35 (See Figure 3) equipped with a R1 rotor and a B1 bob and the appropriate spring a rotational speed of 100 RPM represents a shear rate of 170 sec-1 and a speed of 300 RPM gives a shear rate of 511 sec-1. The Fann 35, which is manufactured by the Fann Instrument Company http://www.fann.com/, the Model 3530,

**Figure 1.** University of Oklahoma Parallel Plate Fracturing Fluid Characterization Facility (Courtesy of the University of Oklahoma).

which is manufactured by Chandler Engineering http://www.chandlerengineering.com/ and the Model 800 8 speed viscometer manufactured by OFI Testing Equipment, Inc. http:// www.ofite.com/ are atmospheric rheometers which limits their use to the boiling point of water. The Fann 50, Chandler 5550 and OFI 130-77 viscometer's are equipped with a pressur‐ ized cup and bob which can be placed into an oil bath for higher temperature measurements. Fluids, including foam, can be dynamically flowed into the cells so that the fluid can be measured under the shear conditions that it would experience in the well. These rheometers are very rugged reliable instruments but suffer from a phenomenon called the Weissenberg effect when trying to measure crosslinked viscoelastic fluids. It occurs when a spinning rod, like the rotor, is placed into a solution of polymer. Instead of being thrown outward the polymer chains entangle on the rod supporting the bob causing the polymer solution to be drawn up the rod. Figure 4 shows what the Weissenberg effect looks like. As temperature increases and the gel thins the issue goes away to a certain extent and modern rheometers try to control the effect. Overall the effect can result in some very misleading data and care must be taken when very odd looking, unusual data is presented. The testing problem is com‐ pounded in that, as illustrated in Figure 5, many fracturing fluids (particularly crosslinked gels) are not truly fluids. Trying to characterize these materials with a "viscosity" can be very difficult. Fortunately, even for these fluids, temperatures above about 120°F make the behavior more predictable.

**Figure 3.** Rheometer's for testing fracturing fluids.

**Figure 2.** The geometry of a curette "Cup & Bob" Viscometer

Fracturing Fluids

15

http://dx.doi.org/10.5772/56192

**Figure 2.** The geometry of a curette "Cup & Bob" Viscometer

which is manufactured by Chandler Engineering http://www.chandlerengineering.com/ and the Model 800 8 speed viscometer manufactured by OFI Testing Equipment, Inc. http:// www.ofite.com/ are atmospheric rheometers which limits their use to the boiling point of water. The Fann 50, Chandler 5550 and OFI 130-77 viscometer's are equipped with a pressur‐ ized cup and bob which can be placed into an oil bath for higher temperature measurements. Fluids, including foam, can be dynamically flowed into the cells so that the fluid can be measured under the shear conditions that it would experience in the well. These rheometers are very rugged reliable instruments but suffer from a phenomenon called the Weissenberg effect when trying to measure crosslinked viscoelastic fluids. It occurs when a spinning rod, like the rotor, is placed into a solution of polymer. Instead of being thrown outward the polymer chains entangle on the rod supporting the bob causing the polymer solution to be drawn up the rod. Figure 4 shows what the Weissenberg effect looks like. As temperature increases and the gel thins the issue goes away to a certain extent and modern rheometers try to control the effect. Overall the effect can result in some very misleading data and care must be taken when very odd looking, unusual data is presented. The testing problem is com‐ pounded in that, as illustrated in Figure 5, many fracturing fluids (particularly crosslinked gels) are not truly fluids. Trying to characterize these materials with a "viscosity" can be very difficult. Fortunately, even for these fluids, temperatures above about 120°F make the behavior

**Figure 1.** University of Oklahoma Parallel Plate Fracturing Fluid Characterization Facility (Courtesy of the University of

more predictable.

Oklahoma).

14 Effective and Sustainable Hydraulic Fracturing

**Figure 3.** Rheometer's for testing fracturing fluids.

**1.** Newtonian Fluid - A Newtonian fluid has a linear relation between shear rate and shear

Fracturing Fluids

17

http://dx.doi.org/10.5772/56192

**2.** Bingham Plastic - A Bingham Plastic differs from a Newtonian fluid in that a non-zero shear stress called the Plastic Yield Value is required to initiate fluid flow. The slope of the shear rate/shear stress data is labeled Plastic Viscosity and this model is routinely used

**3.** Power Law Fluid - This is the most common fluid model used for current fracturing fluids and for this rheological model the shear stress/shear rate data give a linear relation on loglog scales. The slope of this log-log line is denoted by n', and this is labeled the Flow Behavior Index. n'=1 implies a Newtonian fluid; n'>1 is called a shear stiffening fluid; and n'<1 is a shear softening fluid. n' is generally less than 1 for fracturing fluids. The shear stress at a shear rate of "1" is labeled the Consistency Index and is denoted by K'. For real fluids K' and n' change with temperature and time with K' generally decreasing and n'

For non-Newtonian fluids (a Power Law fluid being one example) the "apparent viscosity - (ưa) " is used as a shorthand way of characterizing the fluid. Apparent viscosity (ưa) is illustrated in Fig. 7 and is the ratio of shear stress to shear rate - at a particular value of shear

stress and fluid viscosity is the slope of the shear rate versus shear rate data.

for cements and many drilling muds.

tending toward unity.

**Figure 6.** Rheological Models

**Figure 4.** The Weissenberg Effect

**Figure 5.** Example of a Complex Dehydrated Cross-linked gel

#### **5. Rheological models**

The tests described above measure the shear stress generated by specific increasing shear rates (called a ramp), and this data is converted to a "viscosity" value by using a rheological model to describe fluid behavior. Figure 6 shows the three models that are in common use by the oil industry and these are:


#### **Figure 6.** Rheological Models

**Figure 4.** The Weissenberg Effect

16 Effective and Sustainable Hydraulic Fracturing

**Figure 5.** Example of a Complex Dehydrated Cross-linked gel

The tests described above measure the shear stress generated by specific increasing shear rates (called a ramp), and this data is converted to a "viscosity" value by using a rheological model to describe fluid behavior. Figure 6 shows the three models that are in common use by the oil

**5. Rheological models**

industry and these are:

For non-Newtonian fluids (a Power Law fluid being one example) the "apparent viscosity - (ưa) " is used as a shorthand way of characterizing the fluid. Apparent viscosity (ưa) is illustrated in Fig. 7 and is the ratio of shear stress to shear rate - at a particular value of shear rate. Thus a fluids apparent viscosity depends on the shear rate at which the viscosity is measured (or calculated). For a Power Law Fluid with n'<1, the apparent viscosity will decrease with increasing shear rate.

**Figure 7.** Apparent viscosity using a Power Law Equation

To determine n' and K' a fluid is placed in a rheometer and sheared at a constant rate while the temperature is brought to equilibrium. Periodically the fluid n' and K' is measured by bringing the shear rate up, holding the rate for a few seconds then increasing the rate again typically over a range of at least 4 shear rates. This is termed a ramp and is typically done every 30 minutes during the fluid test. Figure 8 shows an example of a shear stress vs shear rate set of ramps that was provided by C&A Inc. - http://www.candalab.com/. Note that for each ramp four shear rates where used. The slope of the line is the n' and the intercept at a 0 shear rate is the K'. Using this information an apparent viscosity for any shear rate can be calculated with the following equation.

data was measured. In addition, **during the testing the fluid should be sheared at a shear rate somewhat representative of the behavior expected in the fracture**. This is typically on the order of 50 sec-1, but for some soft rock treatments the shear rate may be much lower than

**Figure 8.** A set of shear stress vs shear rate set of ramps along with the calculation of apparent viscosity at three shear

Fracturing Fluids

19

http://dx.doi.org/10.5772/56192

As the fluid is pumped through the surface equipment, well tubular, perforations and fracture it is subjected to a range of shear rates that may have a detrimental effect on the fluid rheology. For example Figure 9 shows the apparent viscosity for a borate crosslinked HPG that was used to fracture a well in China. A series of premature screenouts had occurred and an evaluation was conducted to determine why. The well was completed with an open annulus and a tubing string and the treatments were being pumped down the annulus. The shear rate was calculated to be 2200 s-1 and the time in the tubing/casing annulus was 5 minutes. As the figure shows the apparent viscosity without the 5 minutes of high shear was 800 cps but if subjected to shear was about 20 cps. The fluid did recover its viscosity but it took 80 minutes. The higher proppant

this, and in some hard rock treatments, the shear rate may be much greater.

**6. Shear history simulation**

rates.

*μa* <sup>=</sup> <sup>448000</sup> *<sup>K</sup>* ' (*SR*)1-*<sup>n</sup>*'

Where μa = Apparent viscosity in cps


Service company literature reports viscosity at different shear rates (usually 170 or 511 sec-1) and the shear rate in a fracture can be as low as 30 to 40 sec-1. The example shows that the identical fluid might be reported by one company to have a viscosity of 300 cp (170 sec-1), by another to have 200 cp (511 sec-1), and the fluid may actually have in excess of 600 cp in the fracture (at 40 sec-1). In selecting a fluid it is important to know at what shear rate the viscosity

**Figure 8.** A set of shear stress vs shear rate set of ramps along with the calculation of apparent viscosity at three shear rates.

data was measured. In addition, **during the testing the fluid should be sheared at a shear rate somewhat representative of the behavior expected in the fracture**. This is typically on the order of 50 sec-1, but for some soft rock treatments the shear rate may be much lower than this, and in some hard rock treatments, the shear rate may be much greater.

### **6. Shear history simulation**

rate. Thus a fluids apparent viscosity depends on the shear rate at which the viscosity is measured (or calculated). For a Power Law Fluid with n'<1, the apparent viscosity will decrease

To determine n' and K' a fluid is placed in a rheometer and sheared at a constant rate while the temperature is brought to equilibrium. Periodically the fluid n' and K' is measured by bringing the shear rate up, holding the rate for a few seconds then increasing the rate again typically over a range of at least 4 shear rates. This is termed a ramp and is typically done every 30 minutes during the fluid test. Figure 8 shows an example of a shear stress vs shear rate set of ramps that was provided by C&A Inc. - http://www.candalab.com/. Note that for each ramp four shear rates where used. The slope of the line is the n' and the intercept at a 0 shear rate is the K'. Using this information an apparent viscosity for any shear rate can be calculated with

/sec)

and the shear rate in a fracture can be as low as 30 to 40 sec-1

Service company literature reports viscosity at different shear rates (usually 170 or 511 sec-1

identical fluid might be reported by one company to have a viscosity of 300 cp (170 sec-1

)

), by

. The example shows that the

), and the fluid may actually have in excess of 600 cp in the

). In selecting a fluid it is important to know at what shear rate the viscosity

with increasing shear rate.

18 Effective and Sustainable Hydraulic Fracturing

**Figure 7.** Apparent viscosity using a Power Law Equation

the following equation.

n' = flow behavior index

SR = Shear Rate in Sec -1

fracture (at 40 sec-1

Where μa = Apparent viscosity in cps

K' = the Consistency Index in (lbf/ft2

another to have 200 cp (511 sec-1

*μa* <sup>=</sup> <sup>448000</sup> *<sup>K</sup>* ' (*SR*)1-*<sup>n</sup>*'

> As the fluid is pumped through the surface equipment, well tubular, perforations and fracture it is subjected to a range of shear rates that may have a detrimental effect on the fluid rheology. For example Figure 9 shows the apparent viscosity for a borate crosslinked HPG that was used to fracture a well in China. A series of premature screenouts had occurred and an evaluation was conducted to determine why. The well was completed with an open annulus and a tubing string and the treatments were being pumped down the annulus. The shear rate was calculated to be 2200 s-1 and the time in the tubing/casing annulus was 5 minutes. As the figure shows the apparent viscosity without the 5 minutes of high shear was 800 cps but if subjected to shear was about 20 cps. The fluid did recover its viscosity but it took 80 minutes. The higher proppant

concentrations were settling out near the wellbore and causing the screenouts. The buffer package was adjusted by the service provider and that cured the problem.

**Figure 10.** Shear History Simulation Laboratory Equipment

Figure 11.Slurry Viscosity Multiplier as a function of proppant concentration.14

f prop fluid Fall Rate = V ft/sec = 1.66x10 D /<sup>μ</sup> SG – SG Inline formula

SG prop = the specific gravity of the proppant (i.e. 2.65 for sand) SGfluid = the specific gravity of the fluid (i.e. 1 for water)

The rate of fall for proppant is normally calculated using Stoke's Law which can be written as:

Stokes's Law is generally not valid for Reynolds numbers much in excess of unity15 or for hindered settling due to proppant clustering in static fluids16. For crosslinked fluid the actual fall rate may be much less than Stokes Law. Hannah and Harrington17 present lab data that shows that proppant in crosslinked fluids falls at a rate which is reduced by about 80% when compared to non-crosslinked linear gels with the same apparent viscosity. The rate of proppant fall in foams and emulsions is also much less than would be indicated by using the apparent viscosity in Stoke's Law18. Another factor affecting proppant fall is the particle concentration which increases slurry viscosity (Figure 11). This retards or hinders the proppant fall because of clustered settling16 in static fluids. Finally the slurry flowing down a fracture is generally much lower that the shear rate of 170 or 511 sec-1 used to

**2 4 6 8 10 12 14 <sup>1</sup>**

**lb Sand / Liquid Gallon**

Fracturing Fluids

21

http://dx.doi.org/10.5772/56192

When all of these factors are put together they can significantly affect the viscosity. To provide an example consider a crosslinked

1. Shear Rate Correction – If the fluid has an n' of 0.6 and the shear rate in the fracture is 50 sec-1, the effective apparent

gel which has a reference apparent viscosity at 170 sec-1 of 50 cps after four hours at reservoir temperature.

viscosity in the fracture would be (170/50)1-n' times the measured viscosity or (1.63\*50 = 81 cps).

**8. Proppant fall rates** 

**2**

**3**

**Viscosity Multiplier**

**5 7**

**10**

Where:

5 2

**Figure 11.** Slurry Viscosity Multiplier as a function of proppant concentration.14

D = the average proppant diameter in feet f = the apparent viscosity of the fluid in Cps

report the fluid apparent viscosity.

**Figure 9.** Viscosity Profile for a Borate Crosslinked HPG with and without shear history simulation.

Reference 13 provides a detailed procedure on how to do shear history simulation. The equipment needed is shown in Figure 10. Because the flow in the tubulars is in pipe flow rather than slot flow using a curette "Cup & Bob" viscometer at high shear rate can be misleading. The shear rate in the tubular is a function of pump rate and tubing size. The equations for determining shear rate are included in reference 13.

#### **7. Slurry viscosity**

Another factor affecting viscosity is the addition of proppant to the fracturing fluid to from slurry. For a Newtonian fluid the increase in viscosity due to proppant can be calculated from a equation originally developed by Albert Einstien14. The chart shown in Figure 11 demon‐ strates this effect. The figure shows that an 8 ppg slurry has an effective viscosity about 3 times that for the fracturing fluid alone. This increased viscosity will increase net treating pressure and may significantly impact treatment design. This increase in slurry viscosity also retards proppant fall as discussed below.

**Figure 10.** Shear History Simulation Laboratory Equipment

concentrations were settling out near the wellbore and causing the screenouts. The buffer

package was adjusted by the service provider and that cured the problem.

20 Effective and Sustainable Hydraulic Fracturing

**Figure 9.** Viscosity Profile for a Borate Crosslinked HPG with and without shear history simulation.

determining shear rate are included in reference 13.

**7. Slurry viscosity**

proppant fall as discussed below.

Reference 13 provides a detailed procedure on how to do shear history simulation. The equipment needed is shown in Figure 10. Because the flow in the tubulars is in pipe flow rather than slot flow using a curette "Cup & Bob" viscometer at high shear rate can be misleading. The shear rate in the tubular is a function of pump rate and tubing size. The equations for

Another factor affecting viscosity is the addition of proppant to the fracturing fluid to from slurry. For a Newtonian fluid the increase in viscosity due to proppant can be calculated from a equation originally developed by Albert Einstien14. The chart shown in Figure 11 demon‐ strates this effect. The figure shows that an 8 ppg slurry has an effective viscosity about 3 times that for the fracturing fluid alone. This increased viscosity will increase net treating pressure and may significantly impact treatment design. This increase in slurry viscosity also retards

**8. Proppant fall rates Figure 11.** Slurry Viscosity Multiplier as a function of proppant concentration.14

5 2

D = the average proppant diameter in feet f = the apparent viscosity of the fluid in Cps

report the fluid apparent viscosity.

Where:

Figure 11.Slurry Viscosity Multiplier as a function of proppant concentration.14

f prop fluid Fall Rate = V ft/sec = 1.66x10 D /<sup>μ</sup> SG – SG Inline formula

SG prop = the specific gravity of the proppant (i.e. 2.65 for sand) SGfluid = the specific gravity of the fluid (i.e. 1 for water)

The rate of fall for proppant is normally calculated using Stoke's Law which can be written as:

Stokes's Law is generally not valid for Reynolds numbers much in excess of unity15 or for hindered settling due to proppant clustering in static fluids16. For crosslinked fluid the actual fall rate may be much less than Stokes Law. Hannah and Harrington17 present lab data that shows that proppant in crosslinked fluids falls at a rate which is reduced by about 80% when compared to non-crosslinked linear gels with the same apparent viscosity. The rate of proppant fall in foams and emulsions is also much less than would be indicated by using the apparent viscosity in Stoke's Law18. Another factor affecting proppant fall is the particle concentration which increases slurry viscosity (Figure 11). This retards or hinders the proppant fall because of clustered settling16 in static fluids. Finally the slurry flowing down a fracture is generally much lower that the shear rate of 170 or 511 sec-1 used to

When all of these factors are put together they can significantly affect the viscosity. To provide an example consider a crosslinked

1. Shear Rate Correction – If the fluid has an n' of 0.6 and the shear rate in the fracture is 50 sec-1, the effective apparent

gel which has a reference apparent viscosity at 170 sec-1 of 50 cps after four hours at reservoir temperature.

viscosity in the fracture would be (170/50)1-n' times the measured viscosity or (1.63\*50 = 81 cps).
