Produced and Flowback 

Water Recycling and Reuse

Economics, Limitations, and Technology

Pam Boschee, Oil and Gas Facilities Senior Editor

The demonstration site for the Altela thermal distillation 

process was located at BLX's Sleepy wellsite in the 

Marcellus shale. Photo courtesy of Altela.
February 2014 • Oil and Gas Facilities 17

The demands for the fresh water used in many 

hydraulic fracturing operations are placing pressure 

on water sources in some regions of the United 

States. Because of the high volumes of water needed 

for fracturing (e.g., in the Marcellus, a typical hydraulic 

fracturing operation for a horizontal gas well in a tight shale 

formation requires from 3 to 5 million gallons of water 

over a 2- to 5-day period), the competing demand driven 

by industrial, municipal, and agricultural users has in some 

cases decreased the availability of fresh water and increased 

associated costs. 

Along with higher acquisition costs for fresh water, 

water disposal costs have also increased. Well stimulation 

flowback water and produced water are generally 

considered as waste byproducts of oil and gas production 

and increasingly present logistical difficulties for operators. 

Among the challenges are the transportation of the water 

over long distances and compliance with local jurisdictions 

and environmental regulations related to the disposal of 

water from oil fields. 

Operators are using alternative methods of water 

management, including recycling and reuse of their flowback 

and produced water, to help reduce the total amount of fresh 

water that is used in their operations, and at the same time, 

reduce the volumes of flowback and produced water that 

have to be transported, treated, and disposed. 

Life Cycle Water Costs From 

Acquisition to Disposal

Walter Dale, the strategic business manager for water 

solutions at Halliburton, said that the availability of fresh 

water, transportation costs, water treatment, and disposal 

costs may come to mind first as the major factors in water 

economics. However, the total cost of water needs to be 

considered, including acquisition, transfer to the well, 

transfer from the well to disposal, and disposal (Table 1). 

Once the fracturing procedure itself is completed, 

water returns to the surface as produced water, the naturally 

occurring water found in shale formations that flows to 

the surface throughout the entire production lifespan of 

the well, and flowback, the fraction of hydraulic fracturing 

fluid recovered. 

The fraction of hydraulic fracturing fluid recovered 

varies from play to play (Table 2). For example, flowback 

fluid recovered from wells is reported to range from 9% to 

35% of the fracture fluid used in the horizontal Marcellus 

wells in the northern tier of Pennsylvania (Wood et al.) 

Yoxtheimer (2010) reported an average recovery of flowback 

of 10% (over 30 days) per Marcellus well. Ultimately, from 

300,000 gal to 800,000 gal/well of wastewater are produced. 

Industry data reported to the Pennsylvania Department 

of Environmental Protection show that about 235 million 

gallons of wastewater were produced in the second half of 

2010 (Penn State).

Data compiled by the state of Pennsylvania indicates 

that the volume of flowback water generated from Marcellus 

wells in 2012 was about three times the volume of produced 

water. As more wells go into production, the amount of 

produced water will increase, and the ratio will begin to 

change. While the volume of flowback water is expected 

to remain at approximately 2.5 billion gal/yr until 2019, 

TABLE 1—VARIATIONS IN TOTAL WATER COST

Producing Area Total Cost/bbl (USD)*

Bakken 6.00 to 15.00

Eagle Ford 2.00 to 6.00

Permian Basin 3.00 to 8.00

Marcellus 4.00 to 20.00

Denver-Julesburg 4.00 to 8.00

*Total cost/bbl does not include the cost of brine 

addition.

Source: Halliburton 2014.

TABLE 2—fraction of hydraulic fluid and produced water returned to surface

Producing Area Fraction of Hydraulic Fracturing Fluid Returned as Flowback, % Produced Water Volumes

Bakken 15 to 40 High

Eagle Ford <15 Low

Permian Basin 20 to 40 High

Marcellus 10 to 40 Moderate

Denver-Julesburg 15 to 30 Low

Source: Halliburton 2014.
18 Oil and Gas Facilities • February 2014

the amount of produced water is forecast to rise steadily 

until it surpasses the amount of flowback water in 2019 at 

2.7 billion gal.

Options for Flowback and Produced 

Water Management

Flowback water management options include direct reuse 

without treatment (blending with fresh water for reuse in 

hydraulic fracturing); on-site treatment and reuse; off-site 

treatment and reuse; and off-site treatment and disposal. 

Direct reuse incurs minimal cost, but results in the 

potential for well plugging. On-site treatment reconditions 

the water at a moderate cost and has a decreased potential 

for well plugging. Off-site treatment and reuse incurs high 

transportation costs, while off-site treatment and disposal 

incurs high transportation and disposal costs.

Disposal using injection wells is limited in many areas. 

Pennsylvania currently has about seven brine disposal 

wells. Only one is a commercial well, and it has limited or 

no available capacity and is not permitted for Marcellus 

wastewater disposal. New York has six brine disposal wells, 

West Virginia has 74, and Ohio has 159. Issues in geological 

formations make it difficult to site the disposal wells in 

Pennsylvania and West Virginia (Penn State). 

Of the approximately 250 injection wells serving the 

Marcellus play, approximately three-fourths of the deep 

injection wells are located in Ohio. Ohio state records show 

that of the 12.2 million bbl of waste and brine disposed 

in its deep injection wells in the first half of 2012, 56% 

of the disposed materials came from Pennsylvania and 

West Virginia. 

Shifting the TDS Paradigm

A primary concern in oilfield water treatment is the level of 

total dissolved solids (TDS) in flowback and produced water, 

which varies by basin and well (Table 3). TDS is a measure 

of dissolved matter in water, such as salts, organic matter, 

and minerals. Inorganic constituents (sodium, calcium, and 

chloride picked up from the rock formation) contribute 

most of the total concentration of TDS. 

Under the federal Safe Drinking Water Act, the US 

Environmental Protection Agency classifies TDS as a 

secondary maximum contaminant level (sMCL), meaning 

that there is a recommended maximum level of 500 mg/L, 

but no requirement that public water systems meet this 

level. However, states may enforce their own secondary 

standards. TDS is not expected to harm human health at the 

sMCL, but elevated TDS levels may damage water treatment 

equipment or reduce the effectiveness of treatment for other 

contaminants. TDS becomes toxic to aquatic life at certain 

levels by increasing the salinity in freshwater systems and 

changing the composition of the water.

Dale said operators are reevaluating their approaches 

to treating water for TDS removal when aggregating their 

flowback and produced water to be recycled for use in 

hydraulic fracturing completions. General approaches to 

handling the TDS variability include the following:

• Treatment of the water to achieve high quality 

standards by removing boron, calcium, etc. This 

approach may result in increased costs and increased 

waste creation, leading to the conclusion that recycling 

is too expensive to implement.

• Dilution of the water with fresh water, which 

may result in the misapplication of treatment 

technologies that result in well production or fluid 

integrity concerns.

Many treatments do not remove dissolved salts from 

the water, thus requiring the development of brine-tolerant 

fracturing fluid systems and friction reducers or the use of 

distillation to maintain high performance.

The cost of purifying flowback and produced water to 

near potable quality might not be financially feasible, while 

bypassing treatment entirely can pose difficulties in using 

the water effectively for fracturing fluids, Dale said.

The compositions of fracturing fluids vary from one 

product to another, and the design of the fluid varies, 

depending on the characteristics of the target formation and 

operational objectives. The predominant fluids currently 

being used for fracture treatments in the gas shale plays are 

water‐based fracturing fluids mixed with friction‐reducing 

additives (slickwater), linear gel, and crosslinked gel. 

The fracturing fluid used in slickwater operations 

typically comprises about 98% water and sand (as a 

proppant), with additives (e.g., friction reducer, biocide, 

surfactant, scale inhibitor, breaker, and clay stabilizer) 

comprising 2% (Ketter et al. 2006). Polyacrylamide polymers 

are used to reduce the tubular friction pressure (friction 

reducers). Overall, the concentration of additives in most 

slickwater fracturing fluids is 0.5% to 2% with water making 

up from 98% to 99.5% of the volume. Because of its low 

viscosity (from 2 to 3 cP), a high pump rate is required to 

transport proppant in the formation.

Linear gel is water containing a gelling agent, like guar 

or xanthan. Other possible additives are biocides, buffers, 

TABLE 3—average tds found in flowback 

and produced water

Producing Area TDS, mg/L

Bakken 150,000 to 300,000

Eagle Ford 15,000 to 55,000

Permian Basin 20,000 to 300,000

Marcellus 20,000 to 100,000

Denver-Julesburg 20,000 to 65,000

Source: Halliburton 2014.
February 2014 • Oil and Gas Facilities 19

surfactant, breaker, and clay control. Its viscosity, ranging 

from 10 to 30 cP, results in improved proppant transport 

compared to slickwater. 

Crosslinked gel is water containing any of the gelling 

agents used in linear gel and a crosslinker like boron, 

zirconium, titanium, or aluminum. Other possible additives 

are buffers, biocide, surfactant, breaker, and clay control. 

This fluid has a high viscosity, ranging from 100 to 1,000 

cP, which generally results in better proppant transport 

compared to slickwater and linear gel fracture fluids.

Development of crosslinked gel-based water systems, 

such as Halliburton’s UniStim service, which tolerates salt 

concentrations in excess of 300,000 mg/L, has enabled 

operators to use 100% flowback, produced water, and 

alternate sources, Dale said. 

To reuse high-TDS water effectively in crosslinked 

gel-based hydraulic fracturing fluids, the water must first be 

treated. The goal of the treatment is to remove only minerals 

that hinder the development of the crosslinked fluid or that 

cause scale buildup in wells, he said. In these cases, treatment 

is done to the extent required to ensure production and fluid 

integrity, creating less waste for disposal. 

The development of high-TDS tolerant friction reducers 

has resulted in cost advantages by reducing the amount 

of polymer required in slickwater. Case studies of wells in 

Canada’s Montney and Horn River shale plays that were 

treated with brine-tolerant friction reducers demonstrated 

that their performance in brines was similar to that 

achieved with conventional friction reducers in fresh water 

(Paktinat 2011). 

An example of the cost benefits associated with 

freshwater conservation were based on a Montney well 

located in northeastern British Columbia, where production 

water was used after commingling with freshwater sources. 

The total amount of water required for the well (20 zones) 

was about 340,000 bbl. Using flowback water and assuming 

two cases of 30% and 50% fluid recoveries, from 113,000 

bbl to 170,000 bbl of fresh water could be saved per well. By 

using a brine-tolerant friction reducer and with reuse of all 

flowback water, the estimated savings were about USD 1.4 

million for the treatment of one well. The estimate assumed 

that no water was sent for disposal (Tables 4 and 5).

One Size Does Not Fit All

Dale said that the decision to recycle flowback and produced 

water is dependent upon the economic factors for each 

operator. The number of wells, amounts of flowback and 

produced water, and the proximity of these sources for 

aggregation are important factors in determining water 

management. “The ability to recycle high volumes of water 

is the goal. It’s a function of how much available impaired 

water you have in proximity.

“When the Bakken first started, there were insufficient 

water volumes to consider recycling. But with the increased 

rig count, the flowback volumes are higher, and it makes a 

lot of produced water now that it’s a few years old. Operators 

are hauling 12 million bbl of water to disposal wells, while 

they are using 9 million bbl of fresh water. It’s not practical 

to use the entire volume of 12 million bbl of the disposal 

water to replace the 9 million bbl of fresh water. It’s about 

proximity,” Dale said.

In locations where the flowback and produced water 

volumes are not high, aggregation will eliminate disposal 

and acquisition of one barrel of fresh water for every barrel 

that is reused. He said, “You’re also going to reduce your 

brine purchase and reduce double-trucking costs.”

TABLE 4—total cost of one well in

montney shale using only fresh water

$/bbl Volume, bbl Total Cost, $

Trucking + 

fresh water cost

3.35 339,606 1,137,680

Flowback 

disposal cost

8.00 169,803 1,358,424

Cost to recycle/

reuse flowback 

+ transfers

2.75 0 0

Total cost/well 2,496,104

Source: Paktinat et al 2011.

TABLE 5—total cost of one well in

montney shale using only fresh water

and flowback water (50% Fracturing 

fluid recovery)

$/bbl Volume, bbl Total Cost, $

Trucking + fresh 

water cost

3.35 165,803 568,840

Flowback 

disposal cost

8.00 0 0

Cost to recycle/

reuse flowback 

+ transfers

2.75 165,803 466,958

Total cost/well 1,035,798

Note: Total volume of water used was 339,606 bbl 

(50% fresh, 50% of flowback)

Source: Paktinat et al 2011.
20 Oil and Gas Facilities • February 2014

In the Permian Basin, older conventional wells 

are producing high volumes of water and are tied by 

gathering lines to a central disposal facility. Dale described 

a customer’s effort to develop a hub and spoke model to 

accommodate an entire field, which was too large for the 

model to be economically feasible. “The reality was that the 

customer had the most volume of water production, not in 

the center of the spoke, but in the top right-hand quadrant 

of the spoke. In this case, it makes sense to recycle in that 

quadrant, but doesn’t make sense to recycle in the bottom 

left-hand quadrant.”

Dale said that operators should look for alternate 

sources of water in proximity to their unconventional 

completions that require high volumes of water. “Look for 

the high volumes of impaired waters, such as flowback, 

produced water, and brackish water wells.” 

He said an operator with a project located near a 

refinery is considering aggregating its flowback, produced 

water, and brackish water with water available from the 

refinery. In this case, the refinery’s water quality is suitable 

for making fracturing fluids.

Increasingly, asset managers are becoming the decision 

makers in an organization’s water recycling approaches. 

Dale said, “Some organizations are realizing this. The senior 

executives want to recycle, but the completions engineers 

don’t have the budget for it. These decisions are beginning to 

involve the P&L (profit and loss) people in the company.”

Water Treatment Technologies

Two broad classifications of technologies available for 

treatment and reuse of flowback and produced water are 

conventional treatment and advanced treatment technology, 

both of which have environmental, economic, and energy 

effects that are related to the quality of flowback and 

produced water.

Conventional treatment includes flocculation, 

coagulation, sedimentation, filtration, and lime softening 

water treatment processes. These methods are generally 

effective in removing nondissolved constituents, such 

as total suspended solids, oil and grease, and hardness 

compounds. Although conventional processes can be 

energy-intensive, they are typically less energy-intensive 

than the salt separation treatments, which will be discussed 

below. Simple filtration methods with minimal chemical 

inputs have lower energy, environmental, and economic 

effects. 

Advanced treatment technologies, such as reverse 

osmosis membranes, thermal distillation, evaporation 

and/or crystallization processes, are used to treat TDS. 

The thermal and membrane processes require more 

energy than the conventional methods. Additionally, in 

most cases, conventional processes are used upfront to 

remove the nondissolved constituents prior to the TDS 

treatment processes.

A recently introduced technology for water deslination/

decontamination in the Marcellus shale play implements 

an internal heat transfer process that allows the reuse of the 

latent heat of condensation to offset the total latent heat of 

evaporation required in conventional thermal distillation. 

Incoming dirty water is converted into clean distilled water 

and a concentrated solution of dirty water (Fig. 1). 

By recapturing the energy used to evaporate water, the 

AltelaRain process yields about four times the amount of 

distilled water per energy input as tradition distillation/

evaporation techniques without using pressure (Bruff and 

Jikich 2011). 

The process begins with the produced water that is 

collected in an on-site holding tank. Following its transfer 

by pump to a containerized system, the produced water 

is circulated continuously through 10 towers. The towers 

are designed to evaporate pure water from the brackish 

produced water. The evaporated water is then condensed 

within the same tower, on the opposite side of thin 

plastic sheets.

The condensed water, which is of distilled water 

quality, is collected and transferred from the towers to a 

distilled water holding tank. The concentrated water is 

eventually concentrated up to five times higher TDS content 

and then pumped out of the system for disposal. The 

distilled water is also pumped from the system and made 

available for recycling and reuse. The water quality of the 

treated distilled water meets or exceeds the Pennsylvania 

Department of Environmental Protection’s water quality 

discharge requirements.

Two wastewater treatment facilities using the 

technology are located in western Pennsylvania. The facility 

located in McKean county is owned and operated by 

Casella-Altela Regional Environmental Services. Situated 

adjacent to the McKean county landfill, the facility uses 

landfill gas as its energy source. Owned and operated by 

Clarion Altela Environmental Services, the facility located 

in Clarion county uses waste heat from the waste-coal-fired 

Piney Creek Power Plant.

Each facility is able to process up to 12,000 B/D (about 

500,000 gal) of wastewater, which can then be reused for 

well operations or discharged into surface waterways.

Bruff and Jikich (2011) reported the total treatment 

cost as USD 5.29/bbl at the completion of a National 

Energy Technology Laboratory (NETL) demonstration 

project in 2011, prior to the technology’s implementation 

at the wastewater treatment facilities. The cost included 

the trucking and disposal of the concentrated dirty water. 

This total cost represented a savings of 16% compared 

to trucking and disposal costs without treatment by the 

system. The authors noted that real-world savings would 

be larger, because of the high labor costs involved with the 

NETL demonstration project. OGF

Oil and Gas Facilities has published a series of in-depth 

articles about water management for unconventional 

resources in the Water Treating Insights column. The 

first article was published in June 2013. This month, 
February 2014 • Oil and Gas Facilities 21

methods of controlling biological activity in hydraulic 

fracturing  operations are discussed.

For Further Reading

SPE 103232 A Field Study Optimizing Completion 

Strategies for Fracture Initiation in Barnett Shale 

Horizontal Wells by A. Ketter, Devon Energy et al.

SPE 149272 Case Studies: Impact of High Salt Tolerant 

Friction Reducers on Fresh Water Conservation in 

Canadian Shale Fracturing Treatments by J. Paktinat, et 

al., Trican Well Service.

SPE 149466 Field Demonstration of an Integrated Water 

Treatment Technology Solution in Marcellus Shale by M. 

Bruff, Altela, and S.A. Jikich, US Department of Energy/

National Energy Technology Laboratory.

ALL Consulting, 2009. Horizontally Drilled/High-Volume 

Hydraulically Fractured Wells Air Emissions Data.

Bruff, M., Godshall, N., and Evans, K. 2011. An Integrated 

Water Treatment Technology Solution for Sustainable 

Water Resource Management in the Marcellus Shale. 

Final Scientific/Technical Report DE-FE0000833.

Penn State College of Agricultural Sciences Cooperative 

Extension. 2011. Marcellus Shale Wastewater Issues in 

Pennsylvania—Current and Emerging Treatment and 

Disposal Technologies. http://extension.psu.edu.

Susquehanna River Basin Commission, 2012. SRBC'S Role 

in Regulating Natural Gas Development, http://www.srbc.

net/programs/docs/NaturalGasFAQ_20120323_140574v1.

pdf.

Wood, Ruth, et al. 2011. Shale Gas: A Provisional 

Assessment of Climate Change and Environmental 

Impacts. The Tyndall Centre, University of 

Manchester, http://www.landbou.com/content/

uploads/ArticleDocument/e117d35e-263d-4e94-9c27-

02199efbc60c.pdf. 

Yoxtheimer, D. 2010. Water Management Options for 

Marcellus Natural Gas Development. Penn State College 

of Agricultural Sciences Cooperative Extension, Marcellus 

Shale Educational Webinar Series. http://extension.psu.

edu/.

Waste heat or steam input Brackish produced water stream

Energy reuse

(without a pressure vessel)

Condensation chamber Evaporation chamber

Microthin noncorrodible thermally

conductive water-impermeable wall

Exit air Ambient air

Distilled water stream Concentrated water stream

Saturated carrier gas

Heat

Exchange

Heat

Exchange

Fig. 1—Altela's thermal distillation process heats wastewater to produce clean water vapor by using an internal heat transfer process 

that reuses the latent heat of condensation to offset the total latent heat of evaporation required in conventional thermal distillation. 

Image courtesy of Altela.
22 Oil and Gas Facilities • February 2014