TECHNOLOGY UPDATE

30 JPT • JUNE 2013

The beneficial use of produced water is 

receiving great attention in the oil and 

gas industry. As oil and gas are produced, large quantities of water containing high amounts of total dissolved solids (TDS) are produced in the process. 

Most of the  high-saline produced water 

is reinjected into disposal wells. Reclaiming produced water as the base fluid for 

hydraulic fracturing not only helps to alleviate the industry’s dependence on fresh 

water, but also lowers the overall cost of 

the fracturing treatment.

Contents of Produced Water

Produced water usually comprises the 

formation water and the injected fluids 

from previous treatments. It can contain 

hydrocarbons, high levels of TDS, suspended solids, and residual production 

chemicals. The use of produced water 

for hydraulic fracturing has many advantages, such as reduction in disposal of 

produced water, reduction of freshwater consumption during completion and 

production operations, and realization 

of economic benefits by the operator. If 

produced water is gathered at or near 

the production site and a minimal treatment is applied in hydraulic fracturing 

fluids, recycling and reuse programs may 

become economically and environmentally beneficial. 

As hydraulic fracturing in shale 

plays continues to require large amounts 

of fresh water for oilfield operations 

(i.e., 4 to 6 million gallons per well in 

some cases), reusing produced water 

reduces freshwater consumption. With 

increased restrictions on water availability from subsurface or surface sources, 

fresh water is becoming more difficult 

to obtain. 

In some basins, the use of produced 

water in oil and gas drilling and slickwater-based fracturing treatments has 

been explored. Typically, these applications use water with low TDS levels. 

Little work has been done on the use 

of produced water with high TDS levels (>200,000  ppm) in fracturing fluids designed with linear or crosslinked 

gel bases.

Treating High-TDS Water

To reuse high-TDS produced water effectively in crosslinked gel-based hydraulic fracturing fluids, the water must first 

be treated. The treatment need not generate potable or fresh water, as some oil 

and gas industry water treatments do. 

The goal of the treatment is to remove 

only minerals that hinder the development of the crosslinked fluid or that 

cause scale buildup in the well. One effective form of produced water treatment is 

electrocoagulation (EC).

In EC, an electric current is applied 

across metal plates to remove various 

contaminants from the water. Heavy 

metals (ions) and colloids (organics and 

inorganics) are primarily held in solution 

by electrical charges and particle size. 

The electrical charge applied to the solution of contaminated water destabilizes 

the charges on the particles and generates a coagulation reaction. 

A produced water sample was treated using a bench-scale EC process. This 

step in the recycling program removes 

specific contaminants, including suspended solids, which allows the treated water to be used in future fracturing 

applications. Fig. 1 shows a visual comparison of produced water samples, one 

untreated and the other treated. In the 

EC treatment, the suspended solids are 

Treatment Enables High-TDS Water Use 

as Base Fluid for Hydraulic Fracturing 

Paul D. Lord, SPE, and Renee LeBas, SPE, Halliburton

Fig. 1—A visual comparison of untreated, left, and electrocoagulation-treated 

produced water.

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TECHNOLOGY UPDATE

32 JPT • JUNE 2013

concentrated into a waste stream that 

accounts for 3% to 5% of the total volume. This waste stream can be reduced 

further by approximately 90% through 

the use of a filter press. This step enables 

the removal of the dry solids and the filtration of the water, which is returned to 

the EC treatment stream.

Scaling Tendencies

Produced water can contain high levels 

of scaling ions such as barite, calcite, and 

siderite. It is important to reduce these 

ions, when cost-effective, and control the 

scale, when ion removal is not economic. 

This requires predicting scaling tendencies and developing a scale inhibitor suitable for use in fracturing fluids. 

The Pitzer theory of electrolytes calculates the scaling potential of water over 

a wide range of temperatures, pressures, 

TDS, and cosolvents. A scaling model 

based on the Pitzer theory can be used to 

assess the scaling tendency of produced 

brines under the temperatures and pressures of a potential fracturing treatment. 

EC is very effective in removing 

total suspended solids, turbidity, oil 

and grease, and heavy metals, i.e., copper, zinc, lead, arsenic, chromium, and 

iron. The removal of heavy metals and 

the reduction of divalent ions typically results in EC-treated produced water 

having lower scaling tendencies than 

untreated produced water. When necessary, treated produced water can be 

tested by use of a dynamic scale loop to 

determine the minimum effective dose 

of scale inhibitor. It is recommended 

that scaling tendency tests be performed 

before development of a fracturing fluid 

so that the scale inhibitor is included in 

the fluid analysis.

Recycle and Reuse 

An effective fracturing fluid must have 

these characteristics: easy preparation, 

low fluid loss, good proppant transport 

capacity (viscosity), low pipe friction, 

efficient recovery from the reservoir, and 

low gel residue. Through the use of gelling agents, fluids achieve excellent viscosity. For water-based fluids, guar gum 

and their derivatives, such as hydroxypropyl guar and carboxymethylhydroxypropyl guar (CMHPG), can be used. The 

derivative guars generally have less residues and faster hydration compared with 

non-high-yield guars. Adding borate 

crosslinkers or metal-based crosslinkers, 

such as zirconium, titanium, or aluminum, significantly increases the viscosity 

of guar-polymer gels. 

Crosslinked fluids have a greater capacity to transport proppants than 

uncrosslinked fluids. This transport 

capacity is measured by a rheometer in 

which fluid is tested at specific temperatures and shear rates. In these tests, it 

is possible to observe the transporting 

elastic regime and proppant settling. A 

minimum transport capacity of 400 cp 

measured at 40 sec–1 with a B2 bob is 

commonly desired. This value was used 

as a reference for fracturing fluid tests 

developed using the rheometer.

The proprietary fluid system used in 

this study is designed to hydraulically fracture a sandstone formation (~6,800 ft in 

true vertical depth [TVD]) in the Permian 

Basin. The fluid consisted of a derivative 

polysaccharide guar gum, a metal-based 

crosslinker, oxidizing breaker, breaker catalyst, and a nonemulsifier surfactant. The bottomhole temperature (BHT) 

tested was 140°F. As seen in Fig.  2, the 

crosslinked fluid with 100% EC-treated 

produced water retained more than the 

desired minimum viscosity of 400 cp for 

the required pump time of 60 min.

Field Trial

A field trial was performed in which seven 

wells with a total of 97 fracturing stages were tested using 100% EC-treated 

produced water. The well stimulations 

were performed to evaluate the validity 

of the laboratory test findings under field 

conditions in New Mexico. The sandstone formation depth was approximately 6,800 ft in TVD (11,300 ft in measured depth) with an approximate BHT 

of 140°F. The fracturing fluid system was 

a 30-lbm derivative crosslinked gel. The 

30-lbm derivative crosslinked fluid was 

also used in the bench-scale testing. 

Dynamic break tests of a 30-lbm 

derivative crosslinked gel with treated 

produced water as the base fluid were 

conducted in the laboratory using a Fann 

35 viscometer to help ensure proper fluid 

rheology before stimulation. The derivative guar gum was hydrated in the treated produced water at a pH of less than 7, 

before an oxidizing breaker and a breaker activator were added. 

The gel was crosslinked using a metal-based crosslinker at 140°F. To break 

the crosslinked gel on an optimal basis, 

the amounts of breaker and breaker actiFig. 2—Fluid rheology: The crosslinked fluid system with 100% 

electrocoagulation-treated produced water.

Viscosity

Temperature

0

0

100

200

300

400

500

600

700

0

20

40

60

80

100

120

160

140

10 20 30

Time, min

Viscosity, cp at 40 sec–1

Temperature,  ̊F

40 50 60

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JPT • JUNE 2013 3

vator used were adjusted. The tested fluid 

was designed to maintain greater than 

400 cp—the minimum viscosity recom-

mended for proppant transport capabili-

ties—for 60 min. The fluid performed as 

specified in the test procedures.

One trial well was stimulated using 

1.4 million gallons of treated produced 

fluid and approximately 1.7 million lbm 

of proppant placed in 17 treatment stag-

es. The average treatment pressure was 

1,911 psi and the average treatment rate 

was 47 bbl/min. The pump time for each 

stage was approximately 55 min and con-

sisted of pad and proppant stages with an 

average maximum proppant concentra-

tion of 4.4 lbm/gal. No mechanical failure 

or screening out was encountered during 

the stimulation. The treating pressure 

trends observed were as modeled with 

2% KCl water as the base fluid, indicating 

no adverse effects on the treatment pres-

sure or ability to place proppant when 

using high-TDS treated produced water (>270,000 ppm). 

Reducing Use of Fresh Water

Based on the results of the trial, it is 

feasible to use treated produced water 

with more than 270,000 ppm of TDS as 

the base fluid for hydraulic fracturing. 

The fluid performed comparably to fluid 

developed using fresh water as the base 

fluid under the same test conditions. Ini-

tial oil and gas production rates from the 

stimulated wells in the field trial proved 

comparable to, if not better than, than 

the production rates from an offset well. 

By applying a minimal and cost-effi-

cient treatment to the produced water 

and designing the appropriate fluid 

chemistry, the treated produced water 

was effectively used as a base fluid in 

a crosslinked application. More than 8 

million gallons of fresh water were saved 

and more than 1,400 truckloads were 

eliminated in this multi-well trial, with 

the operator realizing a significant sav-

ings in water management costs. These 

results show a considerable potential for 

the industry to reduce its dependence 

on fresh water for hydraulic fracturing 

and,  hence, reduce the cost of fractur-

ing treatments. JPT

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