CONTENTS

Water Issues Dominate Oil and 

Gas Production..............................1

Editor’s Letter.................................2

Zero Discharge Water 

Management for Horizontal 

Shale Gas Well Development...4

Water Management Strategies 

for Improved Coalbed Methane 

Production in the Black Warrior 

Basin ..................................................7

Testing a Novel Low Temperature 

Desalination Concept for 

Wellhead Treatment of Produced 

Water ............................................. 10

Technical Project Snapshots–

Water Management.................. 14

CONTACTS

Roy Long

Technology Manager

Ultra-Deepwater/Offshore

304-285-4479

roy.long@netl.doe.gov

Ray Boswell

Technology Manager

Natural Gas Technology R&D

412-386-7614

ray.boswell@netl.doe.gov

Eric Smistad

Technology Manager

Oil Technology R&D

281-494-2619

eric.smistad@netl.doe.gov

Fall 2013 Oil & Natural Gas Program Newsletter

1

Water Issues Dominate Oil and Gas 

Production

What Is Produced Water?

Produced water is water trapped in underground formations that is 

brought to the surface along with oil or gas. Because the water has been in 

contact with the hydrocarbon-bearing formation for centuries, it contains 

some of the chemical characteristics of the formation and the hydrocarbon 

itself. It may include water from the reservoir, water injected into the 

formation, and any chemicals added during the production and treatment 

processes. Produced water is also called “brine” and “formation water.” The 

major constituents of concern in produced water are: 

• Salt content measured as (salinity, total dissolved solids, electrical 

conductivity) 

• Oil and grease (this is a measure of organic chemical content) 

• Various natural inorganic and organic compounds or chemical 

additives used in drilling and operating the well

• Naturally occurring radioactive material (NORM)

Produced water is not a single commodity. The physical and chemical 

properties of produced water vary considerably depending on the 

geographic location of the field, the geological host formation, and the 

type of hydrocarbon product being produced. Produced water properties 

and volume can also vary throughout the lifetime of a reservoir.

Produced water is by far the largest volume byproduct or waste stream 

associated with oil and gas exploration and production. Approximately 21 

billion bbl (barrels; 1 bbl = 42 U.S. gallons) of produced water are generated 

each year in the United States from nearly a million wells. This represents 

about 57 million bbl/day, 2.4 billion gallons/day, or 913,000 m3/day (Clark 

and Veil 2009). More than 50 billion bbl of produced water are generated 

each year at thousands of wells in other countries (Figure 1).

Early in the life of an oil well, the oil production is high and water 

production is low. Over time the oil production decreases and the water 

production increases. Another way of looking at this is to examine the ratio 

of water-to-oil volume:

• Worldwide average estimate – 2:1 to 3:1 

• U.S. estimate – 5.1 to 8:1, because many U.S. fields are mature and past 

their peak production (Clark and Veil 2009), although the ratio may be 

even higher as water is not always measured directly. 

• Many older U.S. wells have ratios > 50:1

At some point the cost of managing the produced water exceeds the profit 

from selling the oil. When this point is reached, the well is shut in.
2

Editor’s Letter

Few topics elicit more response today than the issues surrounding produced and frac flowback 

water. The boom in shale development, with the consequent increase in fracturing water use and 

reuse, has upped the ante considerably. That, together with the aging of tradition wells leading to 

increased water cuts, has resulted in a sharp increase in water production, and increased pressure to 

dispose of and/or treat that water in a safe and environmentally responsible manner. 

Treating produced and frac water entails removing a number of chemical constituents. The degree 

to which these constituents must be removed depends on the subsequent disposition of the water. 

Removing specific amounts of various chemical constituents and total dissolved solids (TDS) may 

render the water suitable for reuse in fracturing operations but below regulations for discharge into 

waterways. The variability of produced and frac flowback quality (see table), in addition to the final 

intended disposition of that water, requires a multitude of different water treatment options.

Cost effective technologies for removing dissolved ions from water have been one of the most 

important research challenges for both public and private sector scientists for more than a decade. 

Because produced water can be disposed of through deep well injection at a cost that can be less 

than $2 per barrel, the cost hurdle for these new technologies to become commercial can be very low.

To meet the variability of this demand, a number of treatment, reuse and disposal options have 

emerged from recent research, much of it funded by the U.S. Department of Energy’s National 

Energy Technology Laboratory (NETL). Some of these are detailed in this issue of E&P Focus.
3

In contrast, coal bed methane wells initially produce a large volume of 

water, which declines over time. The methane production starts low, 

builds to a peak, and then decreases.

What is Frac FlowBack Water? 

Flowback is a water-based solution that flows back to the surface during 

and after the completion of hydraulic fracturing. Frac flowback water is 

characteristic of the fluid used to fracture the formation, along with clays, 

chemical additives, dissolved metal ions and total dissolved solids (TDS). 

The water can have a murky appearance from high levels of suspended 

particles. Most of the flowback occurs in the first seven to ten days while 

the rest can occur over a three to four week time period. The volume of 

flowback water is anywhere between 20% and 40% of the volume that 

was initially injected into the well. The rest of the fluid remains absorbed 

in the formation.

Flowback water is not a uniform “raw material” from a process 

development perspective. The physical and chemical properties of 

flowback water vary considerably depending on the geographic location 

of the play, the geological formation, and the chemicals introduced 

during the drilling and fracturing operations. Moreover, flowback 

volume and water properties vary throughout the lifetime of the well. 

The flowback rate is highest initially and then decreases. Although 

there could be wide variation across geographical locations and due to 

operator bias, general flow profiles are shown below:

Time Flowback rate Flowback recovery % frac fluid

1-5 days 100-150 bbl/hr 10-25%

5-15 days 20-60 bbl/hr 8-12%

15-30 days 5-10 bbl/hr 1-5%

30-90 days 10 bbl/day 1-2%

The overall flowback after 90 days is in the range of 15 to 40%, but could 

be higher in certain wells.

As oil fields mature and water/oil ratios rise, and as increased levels of 

hydraulic fracturing in both oil and gas-bearing shales lead to increased 

volumes of flowback water, the challenges of cleaning and/or disposing 

of oilfield waste will only increase.

This newsletter is available 

online at http://www.netl.

doe.gov/E&P Focus

NATIONAL ENERGY 

TECHNOLOGY LABORATORY

1450 Queen Avenue SW

Albany, OR 97321

541-967-5892

2175 University Avenue South 

Suite 201

Fairbanks, AK 99709

907-452-2559

3610 Collins Ferry Road

P.O. Box 880

Morgantown, WV 26507-0880

304-285-4764

626 Cochrans Mill Road

P.O. Box 10940

Pittsburgh, PA 15236-0940

412-386-4687

13131 Dairy Ashford, Suite 225 

Sugar Land, TX 77478

281-494-2516

Visit the NETL website at:

www.netl.doe.gov

Customer Service:

1-800-553-7681

E&P Focus is published by the 

National Energy Technology 

Laboratory to promote the 

exchange of information among 

those involved in natural gas 

and oil operations, research, 

and development.

REFERENCES

Clark, C.E. and J.A. Veil, 2009, Produced Water Volumes and Management Practices in the United States, 

ANL for NETL

Daigle, T.P., 2012, Ultra Deep Water 

Discharge of Produced Water and/or 

Solids at the Seabed, 09121-3100-01 

RPSEA (after TUV-NEL, 2010)

Figure 1. Global Oil and Water Production History and Forecast (TUV-NEL, 2010). The 

above figure highlights a major issue for the oil and gas industry. As the forecast oil 

production remains consistent, the produced water from this production continues to 

increase. The handling of produced water will become increasingly more important. 
4

Zero-Discharge Water Management for 

Horizontal Shale Gas Well Development

West Virginia University, with partners ShipShaper, LLC, and FilterSure, Inc., 

have undertaken a project, with funding from NETL, to develop an on-site 

multi-media filtration system. The five-stage modular design will permit 

efficient system operation and treatment of flowback water at conditions 

that vary over time. 

Background

Shale gas development in the Marcellus gas play in the northern 

Appalachian Basin requires large volumes of water to fracture the 

formation and stimulate production. Known as “frac return water”, 

it and produced water are highly saline and currently require either 

disposal or treatment for reuse or disposal. Both options are expensive. 

Produced water that cannot be readily treated for local disposal (e.g., land 

application) can be hauled to an injection well for disposal. These are EPA 

Class II wells permitted under the federal Safe Drinking Water Act and 

carefully controlled and monitored. Disposal costs are well established. 

In Texas, haulage and disposal costs average $1.47 per barrel. In the more 

populated East, the costs range from $1.68 to $2.10 per barrel. As an 

alternative to deep well disposal, produced water has been processed 

at treatment plants (especially in Pennsylvania) but this practice is being 

scaled back.

The more cost-effective alternative is on-site treatment of the produced 

water to the degree needed for re-use as frac water. Produced water 

has been successfully treated using Reverse Osmosis (RO) as the primary 

treatment technology. However, extension of the RO technology to the 

treatment of flow back from hydraulic fracture operations has required 

pre-treatment technologies designed to extend the life of the RO unit. 

RO protection is especially important during the initial frac water return 

period when the water will contain the maximum suspended solids and 

minimum dissolved solids. 

Re-use technologies are just now being implemented, and as reported 

in a recent Ground Water Protection Council overview: “Current levels of 

interest in recycling and re-use are high, but new approaches and more 

efficient technologies are needed to make treatment and re-use a widespread reality.” The FilterSure multi-media filter technology offers a new, 

cost-effective approach for removing suspended solids while promising an 

improvement in operating efficiency. 

Impact

The successful development of an advanced multi-media filter technology 

for clean-up and re-use of frac return water will advance shale gas 

exploitation and development through improved economics and 

resolution of environmental issues. Improved economics will be achieved 

by the reduction of frac return water trucking and disposal costs. By 

reusing the frac return water for subsequent fractures, the need for new, 

fresh frac water for future wells will be reduced by 30% to 50%, depending 

on the percentage of injected water that is returned after the frac. There 

will be an additional cost savings due to reduced freshwater hauling, 

and labor costs will be minimized because the mobile unit will operate 

continuously with little or no need for an attendant.

Significant environmental benefits will be derived from this technology 

as well. Less fresh water will be needed for future fractures, thus lowering 
5

the demand stress on local streams. Fewer trips with water trucks will 

cause less damage to local roads, reduce fugitive dust and engine exhaust 

emissions, and reduce mud and muddy water which potentially could 

pollute streams. These derived environmental benefits will also provide 

indirect economic benefits through reduced cost of road repairs, and less 

need for local stream remediation. Perhaps the most important benefit 

from cleaner and less disruptive water management will be the “good will” 

of all stakeholders affected by the shale gas development process. 

Accomplishments

FilterSure installed the Mobile Treatment Unit (MTU) and conducted a 

field test at a Marcellus Shale well site (Figures 1,2). The MTU successfully 

supported a nine (9)-stage fracture treatment. The average filtration rate 

during fracture operations was 104 gallons per minute (GPM) with an inlet 

pressure of 52 pounds per square inch (PSIG). The MTU removed 32% of 

the solids, a result similar to that achieved in controlled laboratory tests 

at West Virginia University. During the test the MTU processed 280,000 

gallons of produced water. Of the total volume of water sent to the MTU, 

98.6% was recycled with only 1.4% sent for disposal.

The design phase of a 150 GPM unit has been completed. Testing of a 6 

GPM MTU in the laboratory has shown that 150 GPM throughput can be 

reached.

Figure 1. Equipment layout of the FilterSure Mobile Treatment Unit (MTU).

Figure 2. Piping schematic of the FilterSure MTU.
6

Results of Lab and Field Tests

During a laboratory test using actual frac return water from a site 

similar to the test site, WVU concluded that the new filter unit captured 

particulates at and greater than 3 microns in size. Current industry 

requests are equal to or greater than 20 microns, showing that even at 

high throughput the filter unit exceeds current industry needs. 

No naturally occurring radioactive materials (NORMs) have been found 

in any of the field samples of frac return water received to-date. Any 

heavy metals and radioactive elements/compounds, if any, will be 

contained in the solids removed by filtration and managed as a part of 

the commercial process. Tests on the filter backwash waters following 

treatment of each sample showed “non-detect” levels for As, Cd, Cr, Pb, 

Se, Ag, and Hg. Barium was detected in amounts ranging from 1.61 to 

5.33 mg/l, well below the Maximum Concentrated Level of 100 mg/l set 

for Ba.

One 20-gallon sample of Marcellus frac return water was shipped to 

a provider of Electrical Coagulation (EC) technology for testing as a 

potential pre-treatment option. The EC-treated water was returned to 

WVU for evaluation. The results show that the EC technology had a major 

impact on the distribution of the solids. Specifically, the EC technology 

caused the size distribution of solids to shift from a few microns in size to 

larger solids having a single bell-shaped distribution. 

Three applications of FilterSure to Marcellus Shale frac return water 

reduced the suspended solids by 76%, removing all suspended solids 

greater than 3 microns in size, a good result when compared to the 

most strict industry requirement of 5 microns. Other industry operators 

stipulate either a 5 to 10 micron requirement or standard sand filtration 

with no absolute size requirement. 

Suspended solids in the EC treated water were easily removed with the 

FilterSure technology, resulting in an effluent that was visually clear 

without particulates. The combination EC and FilterSure treatment 

system removed 99.4% of all particles. 

Results of economic analyses indicate that the system resulting from this 

project will be very cost competitive in achieving the ultimate objective 

of zero-discharge of frac return water. Preliminary estimates place the 

cost at $0.80 to $1.22/barrel. 

Responses to a questionnaire developed for this project are providing 

engineering information on volumes of flowback water and water 

chemistry requirements for recycling of flowback water. An Industry 

Contact Group was created to obtain representative water flowback 

samples and information on operating parameters.

The project ended in September 2012. A detailed final report can 

be found at www.netl.doe.gov/technologies/oil-gas. For additional 

information on this project, please contact William Fincham (william.

fincham@netl.doe.gov or 304-285-4268) or Dr. Paul Ziemkiewicz (pziemkie@wvu.edu or 304-293-2867x5441).
7

Water Management Strategies for 

Improved Coalbed Methane Production in 

the Black Warrior Basin

The primary goal of this project is to analyze and develop strategies 

for water resource management within the coalbed methane (CBM) 

reservoirs of the Black Warrior Basin. Undertaken by the Geological Survey 

of Alabama*, the objective of the project was to develop a high-quality 

database and geographic information system (GIS). The objective of this 

system is to provide a basis for the development of efficient regulatory 

guidance by quantifying the environmental impacts of CBM produced 

waters and optimizing production operations and regulatory frameworks. 

Such regulatory guidance will help to provide environmental protection 

while simultaneously ensuring CBM delivery to the marketplace. 

Background

Produced water management is a subject of increasing environmental 

scrutiny. Produced water can be a valuable commodity usable over a 

broad range of municipal, industrial, and agricultural applications. Some 

applications, such as using produced water for hydraulic fracturing, can 

increase efficiency while simultaneously reducing the costs of basic 

CBM operations. Use of produced water outside the CBM industry adds 

value to CBM production operations by facilitating industry, enhancing 

agriculture, and providing vital public services to communities affected by 

distressed water supplies. The CBM resource base in the Black Warrior Basin 

is estimated to be between 10 and 20 trillion cubic feet (Tcf). Cumulative 

CBM production stands at 2.1 Tcf and the most recent USGS assessment 

indicates that an additional 4.6 to 6.9 Tcf may be recoverable. Water 

management issues affect all CBM producers in the Black Warrior Basin. 

These issues need to be critically analyzed and addressed so that full CBM 

recovery potential can be realized. 

Impact

The Black Warrior Basin has a long and rich history of CBM development. 

The wealth of data and the geologic diversity of the basin provide an 

unparalleled opportunity to evaluate water management strategies across 

a spectrum of reservoir conditions. Accordingly, this study will help natural 

gas producers develop basic geologic, hydrologic, and water management 

concepts that can be applied to CBM plays throughout the world. The 

study will apply a spectrum of geologic, hydrologic, geochemical, 

petrologic, GIS, and other computational techniques to characterize the 

Black Warrior Basin reservoir geology and basin hydrology. Study results 

should permit development of new water management strategies that will 

ensure environmental protection, foster beneficial use of produced waters, 

and improve reservoir performance. 

Accomplishments 

Eighty-six water samples were collected for geochemical analysis. 

Additionally, 25 gas samples were collected. Collection of these samples 

completed the sampling phase of the project. Analysis of these samples 

will enable further characterization of the relationship between water 

chemistry and the geologic framework, as well as aid in the development 

of water management strategies. 

Reservoir performance has been analyzed through decline curves and 

production mapping (Figure 1). Numerous variations of production decline 

*Note: In partnership with Black 

Warrior Methane, Coalbed Methane 

Association of Alabama, El Paso 

Exploration and Production, Energen 

Resources, Geomet, HighMount 

Exploration and Production and the 

U.S. Geological Survey
8

curves were identified and some have been found to be characteristic of 

specific producing areas. Areas where erratic production—due to frequent 

well maintenance or water management issues—is common have been 

identified and are indicative of inefficient gas recovery. These areas will be 

further investigated in order to develop water management strategies. 

Discharge points where processed water is released into the Black Warrior 

River have been identified and incorporated into a geographic information 

system. Mapping of these locations aids in the development of water 

management strategies. 

Researchers characterized the petrology of the Upper Pottsville 

sandstones, shales, and coals. Results of authigenic cement analyses 

indicate that sandstone composition has had no tangible impact on 

authigenesis. Stable isotopic analysis of the calcite cement that lines the 

natural factures (cleats and joints) indicates cementation began locally 

early in the unroofing process in formation water with marine affinity; 

however, most of the cementation took place at or near modern burial 

depth and was associated with late-stage bacterial methanogenesis. 

A manuscript was submitted for inclusion in a special volume of the 

International Journal of Coal Geology. Additionally, a manuscript, entitled 

“Dynamics of Thermogenic and Late-Stage Biogenic Gas Generation in 

Coalbed Methane Reservoirs of the Black Warrior Basin,” was delivered at 

the Unconventional Resources Technology Conference held in Denver in 

August 2013.

Going forward, researchers will continue mapping and analyzing 

geochemical data, as well as evaluating various water management 

strategies used in the basin. 

For additional information on this 

project, contact Chandra Nautiyal 

(chandra.nautiyal@netl.doe.gov or 

281-494-2488) or Marcella McIntyreRedden (mmcintyre@gsa.state.al.us

or 205-247-3654).

For a listing of project publications 

please visit the project website at 

http://www.gsa.state.al.us/gsa/cbm/

Coalbed Methane Research.htm

[external site].

Figure 1. Distribution of original-gas-in-place for the Black Warrior Basin
9

Testing a Novel Low Temperature 

Desalination Concept for Wellhead 

Treatment of Produced Water 

US Department of Energy research partners at the New Mexico Institute 

of Mining and Technology, together with Harvard Petroleum Corp., and 

Robert L. Bayless, Producer, LLC., have completed laboratory and field 

pilot testing of a system that relies on a low temperature distillation 

humidification dehumidification (HDH) process to remove salts from 

produced water. Longer term field testing of a 30 barrel per day (Bpd) 

prototype (now underway) will incorporate solar panels to provide heat for 

the process, increasing yields and reducing external power requirements. 

Background

Produced water can be very saline, sometimes nearly six times as salty as 

seawater. For many smaller oil and natural gas producers faced with the 

need to dispose of large volumes of this brine in mature fields with tight 

operating cost constraints, the prospect of a low-temperature system that 

could desalinate the water at the wellhead is very attractive. Pure (or even 

less salty) water could be used for a number of oilfield operations (e.g., 

waterflooding, drilling fluids, stimulation fluids) and/or beneficial uses like 

irrigation, revegetation or livestock water.

Produced water desalination efforts have been focused on 

demineralization technologies that include reverse osmosis (RO), 

distillation, electrodialysis, freeze-thaw desalination, and ion exchange. 

Air stripping, activated carbon adsorption, membrane filtration, biological 

treatment and wet air oxidation have been widely investigated for 

removing the dissolved organic compounds that are also present in 

produced water. Unfortunately, applications of these technologies can be 

limited due to environmental factors (i.e., freeze-thaw works best in cold, 

dry climates) and energy intensity. Options are needed that are less energy 

intensive and applicable in a wider range of environments.

The HDH Process

The HDH process relies on the mechanism of air humidification at elevated 

temperature and water condensation at low temperature. Air can carry 

large amounts of water vapor at elevated temperature and that water 

vapor will condense when its temperature is dropped. In this system, air is 

used to scrub the produced water feed and then the feed water is sprinkled 

into the top of a chamber filled with packing material for enhanced water/

air contact as air is pumped upwards from the bottom via a blower. The air 

is humidified as it travels to the top and then dehumidified in the adjacent 

condensing chamber. A large air-liquid contact area enhances water 

evaporation by forming a large area of thin water surface for contact with 

the forced air flow.

During the course of this research, bench-scale and field scale prototypes 

employing the HDH process were tested. The results revealed that 

the yield of desalinated water increases as the inlet feed temperature 

increases because the water carrying capacity of the air increases with 

inlet temperature. Supplemental energy sources for adding heat (solar 

panels and possibly co-produced geothermal energy) are being designed 

into the second phase field-scale prototype. Also, employing heat pump 

technology for enhancing latent heat recovery improves energy efficiency. 

Heat released by condensation can be transported to the evaporation side 

of the HDH unit as an additional latent heat source. 
10

Economics of Desalination Technologies

Large-scale water purification techniques like multi-stage flash and reverse 

osmosis achieve operating costs on the order of $0.70 to $1.25 per barrel of 

treated water when large capacity units are employed. These technologies 

are expensive for small water processing volumes and are not feasible for 

locations with limited maintenance schedules and energy hookups. Initial 

evaluation of the results from this project indicates that costs on the order 

of $0.45 to $0.80 per barrel of treated produced water may be possible for 

a 20 Bpd capacity system. The main operating costs for the HDH system are 

related to energy costs for circulating pumps and heating of the inlet feed 

water.

The HDH process is most efficient at a relative humidity below 60–70%.

While the “sweet spot” for deployment is in the desert southwest, 

including highly oil and gas productive regions such as the Permian, San 

Juan, and Paradox basins, the method would also be applicable in most 

Rocky Mountain producing areas and into portions of the Great Plains.

Phase I Results

Phase I of the project involved proof-of-concept for the HDH process using 

a bench-scale unit (Figs. 1 and 2), with the objective of understanding the 

influences of operational parameters such as feed water temperature, 

flow rate, carrying air flow rate on purified water quality, productivity, 

and overall water recovery rate. The results indicated that with a simple 

tubing-shell structured unit (where the separation column was built 

using a plastic shell column and copper pipes as the humidifier and heat 

exchanger), over 98% of dissolved salt was removed.

Experiments with produced water from a coalbed methane well indicated 

that both salt and dissolvable organics were removed efficiently by the 

HDH process. Total dissolved solids were reduced from 19,800 to 77mg/L 

while total organic carbon was reduced from 470.2 mg/L to 17.83 mg/L.

Phase II Results

The second phase of the project was to design and test a field prototype 

with a capacity to treat 30 Bpd of water. In these tests the total clean water 

yield from the process was 18 to 20 percent for the first pass of produced 

water. This result came after several iterations of design changes to 

optimize performance. The limit on inlet concentration was also tested and 

the process showed no drop in performance over a range of 8,500 mg/L to 

Figure 1. Schematic of laboratory scale HDH unit Figure 2. Schematic of separation system operation
11

250,000 mg/L of total dissolved solids (TDS). Ion rejection for the process 

was well over 99 percent with the purified water TDS values in the range of 

200 mg/L or less.

The bench scale tests had identified some problems with the design, 

including insufficient heat transfer within the process chamber and leakage 

between chambers. Some of the design changes implemented in the field 

prototype versus the original bench design (see Figure 3) included:

• Simple oil skimmer to separate remaining oil from produced water

• Flat plate solar collectors sized to heat 20 Bwpd from 41 °F to 158 °F 

(during the prototype field testing a steam generator was used in place 

of the solar panels, which will be activated in Phase III).

• HDH unit with chambers made with stainless steel weirs designed for 

evenly spreading the water and cellulose-based packing material to 

increase the residence time of the fluid and maximize contact time 

between air and water (See Figures 4, 5)

• Cold trap to condense and collect purified water (Figure 6)

The field deployment of the system, installed in a shipping container, took 

place at a produced water gathering site in southeastern New Mexico. 

Throughput of 20 bbls per day during numerous 8-hour test periods was 

carried out over 43 days. The field test proved that produced water could 

be effectively desalinated using the HDH process, at atmospheric pressure 

and relatively low temperatures, with yields of up to 20 percent depending 

on the system configuration.

Figure 3. Schematic of field prototype design
12

Next Steps: Continued Field Testing

The objective of the current phase of this project is to upscale the HDH 

process and demonstrate the viability and cost effectiveness of using solar 

energy to augment the process for continuous operation. The existing 

field prototype has been tested at up to 20 bbl/8 hours using somewhat 

arbitrary inlet rates. It should be feasible to triple that throughput and 

incremental increases to inlet rate may further increase the efficiency of 

this individual unit. 

Solar panels have been sized to produce enough heat to maintain the 

cycle for 24-hour operations, even during winter months, with automation 

for continuous feed of produced water and utilizing solar panels and an 

insulated inlet water storage tank to “bank” heated water for overcast 

days and night operation. Additional testing to determine maximum 

throughput and most efficient throughput rates will be performed. 

Increased automation and maintenance parameters will be evaluated and 

put in place to allow unattended operation for days or weeks at a time.

Finally, a full-scale prototype will be constructed and operated at a field 

gathering site for a period of two months with the goal of reducing 

Figure 4. Top of HDH unit showing stainless steel weir 

construction

Figure 5. Packing material

Figure 6. Water purification system prototype inside shipping container as deployed at well site 

(HDH unit is stainless steel box in background, cold trap is blue box at left)
13

disposed water to less than 20% of original volume. Based on field 

testing with the prototype it is expected that with deployment of solar 

energy the electricity consumption for the HDH system can be reduced 

to 0.16 kWh per barrel and overall produced water purification cost to 

about $0.18/barrel, considerably lower than that for commercial RO 

desalination processes and deep well injection.

Potential Impacts

Many marginal wells that produce less than 10 Bopd are operated near 

the edge of profitability by small operators, who generally do not own 

infrastructure for water transportation or facilities for disposal. Produced 

water must be hauled by truck to disposal sites, a costly process that can 

make an otherwise profitable operation uneconomic. This application 

of cost-effective technology for produced water purification could help 

to give new life to low-yield wells, result in a considerable decline in 

salt water disposal needs, and provide a clean water resource for land 

re-vegetation, oil production operations, or other beneficial uses. In 

addition, any reduction in deep well injection will reduce the risk of 

surface water contamination from transported produced water, and 

may also reduce the need for pipelines and associated rights of way, and 

reduce truck traffic and associated air pollution.

Additional Information

The final report for the first phase of this project has been published 

and is available at (http://www.rpsea.org/projects/07123-05/). For 

further information about this project, contact Chandra Nautiyal 

(Chandra.Nautiyal@netl.doe.gov or 281-494-2488) or Liangxiong Li 

(Li@prrc.nmt.edu or 575-835-6721). In addition, two papers have been 

published or accepted for publication:

X. Li, S. Muraleedaaran, L. Li, and R. Lee, “A Humidification 

Dehumidification Process for Produced Water Purification,” Desalination, 

in press, 2010.

S. Muraleedaaran, X. Li, L. Li, and R. Lee, “Is Reverse Osmosis Effective 

for Produced Water Purification: Viability and Economic Analysis,” SPE 

115952, Presented at the 2009 SPE Western Regional Meeting Held in 

San Jose, USA, 24-26, March 2009.

Figure 7. Shipping container encased unit deployed at field produced water facility (steam 

generator and insulated water storage tank shown in front)
14

Technical Project Snapshots—Water Management

In addition to the projects highlighted in the previous section, a number 

of other, DOE research efforts focused on the treatment of produced 

water are summarized below. For details on any of these projects, search 

on the title or project number at www.netl.doe.gov or contact any of the 

Technology Managers listed on the front page. 

Treatment and Beneficial Reuse of Produced Waters 

Using a Novel Pervaporation-Based Irrigation 

Technology (09123-11)

Objective: Develop a user-friendly model that may be used to assess 

the feasibility of the PV irrigation processes in areas defined by different 

climatic and site-specific conditions.

Performer: University of Wyoming

Progress: Laboratory tests have been completed. Based on permeate 

flux performance and observed rejection of salts, the pervaporation 

irrigation membrane process is a viable treatment technology for CBM 

produced waters.

Next Steps: Future work will concentrate on pilot site characterization, 

installation of the pervaporation irrigation (subsurface) lines and 

commencement of a long-term test to be followed by product 

evaluation and an economic assessment

NORM Mitigation and Clean Water Recovery from 

Marcellus Frac Water (10122-07)

Objective: Develop a cost-effective process to recover distilled water 

and a salable salt product from Marcellus frac flowback water.

Performer: GE Global Research

Progress: Lab and pre-pilot studies on several Marcellus frac waters 

have been carried out to establish a pretreatment process for NORM 

removal and membrane distillation (MD) equipment protection.

Next Steps: GECR wil l conduct pilot validations of Marcellus frac water 

treatment and water recovery by MD.

Basin-Scale Produced Water Management Tools and 

Options, Uinta Basin, Utah (11123-08)

Objective: Foster collaboration among producers, users, regulators, 

and local water management interests, providing information necessary 

for effective protection of alluvial aquifers, sustainable produced water 

management, as well as beneficial use of treated produced water.

Performer: Utah Geological Survey

Progress: Work has been initiated on compilation and analysis within 

a geographical information systems (GIS) format of past and new 

information on: thickness, structure, depth, and lithologic nature of all 
15

aquifer/reservoir units in the basin from the surface down through the 

Glen Canyon Group; the regional variations in quality of water, flow 

direction, and temperature produced from the various shale/tight sand 

gas reservoirs across the Uinta Basin; the location, saturated volume, 

and quality of alluvial aquifers; the existing infrastructure for water 

management/reuse; the energy generation potential of geothermal 

produced waters; and location and geochemical and hydrological 

characteristics of aquifers used/proposed for disposal of produced 

water or concentrated brines.

Next Steps: Compilation and statistical analysis of water production 

quantity and quality to identify and forecast produced water 

production volume trends for each discrete shale/tight sand gas 

producing interval.

Development of Plasma Technology for the 

Management of Frac/Produced Water (11122-31)

Objective: Demonstrate a novel plasma-induced water softening process.

Performer: Drexel University

Progress: The project was recently awarded and funded.

Next Steps: A coupled vapor-distillation process will be evaluated and 

reported

Advanced Treatment of Shale Gas Frac Water to 

Produce NPDES Quality Water

Objective: Develop a treatment process for flowback water that combines 

magnetic ballast clarification (MBC) for removal of total suspended solids, 

metals, and naturally occurring radioactive material, and vortex-generating 

and nano filtration membranes for removal of suspended and dissolved 

solids. 

Performer: Southern Research Institute 

Progress: The project was recently awarded and funded.

Cost-Effective Treatment of Flowback and Produced 

Waters via an Integrated Precipitative Supercritical 

Process

Objective: Evaluate the performance of an integrated precipitative 

supercritical (IPSC) process for treating fracturing flowback and produced 

water incorporating solids filtering, ultra-violet light treatment, chemical 

precipitation, and an advanced supercritical water reactor for removal of 

ionic salts.

Performer: Ohio University

Progress: The project was recently awarded and funded.
16

Advancing a Web-based Tool for Unconventional 

Natural Gas Development with Focus on Flowback 

and Produced Water Characterization, Treatment and 

Beneficial Use (11122-53)

Objective: Enhance an existing online produced water management 

tool by improving functionality and user choices, and enlarging the 

water quality database to include compositions of fracturing fluids, flow 

back, produced water, and baseline groundwater and surface water 

compositions for a variety of shale gas and tight gas plays. 

Performer: Colorado School of Mines 

Progress: The project was recently awarded and funded.

Development of GIS-Based Tool for Optimized Fluid 

Management in Shale Operations 

Objective: Develop a GIS-based Optimized Fluids Management (OFM) 

tool that will access and analyze industry, regulatory, public, and research 

databases ,and utilize a computational engine to provide equilibrium 

chemistry predictions and treatment process designs for a given set of 

water quality data. 

Performer: Colorado State University 

Progress: The project was recently awarded and funded.

Novel Engineered Osmosis Technology: A 

Comprehensive Approach to the Treatment and Reuse 

of Produced Water and Drilling Wastewater (10122-39)

Objective: Advance development of the forward osmosis, osmotic 

dilution, and novel ultra-filtration processes for treatment of drilling and 

stimulation wastewater and produced water. These processes utilize 

osmosis as a driving force to extract pure water from highly impaired water 

while minimizing the volume of the concentrated, contaminated stream.

Performer: Colorado School of Mines

Progress: Investigation of the impact of changes in casting (membrane 

manufacturing process) parameters and membrane polymers to improve 

flux and longevity for operations in fouling and scaling environments has 

begun. First generation of novel forward osmosis membranes (capillary 

membranes that enable forced flow on both sides of the membrane and 

are self-supported, versus conventional spiral wound membrane modules) 

manufactured by HTI were received by CSM and testing is underway.

Next Steps: Continue testing of novel membranes and complete 

characterization of membrane performance relative to more conventional 

membranes