Cost Effective Recovery of Low-TDS Frac Flowback 

Water for Re-use

Department of Energy: DE-FE0000784

Final Report

Reporting Period: October 1, 2009 – March 31, 2011

Harish R. Acharya

Principal Investigator

518-387-5875 (Telephone)

518-387-7403 (Fax)

Claire Henderson

Hope Matis

Hareesh Kommepalli

Brian Moore 

Hua Wang

GE Global Research

1 Research Circle, Niskayuna, NY 12309-1027

June 2011

Submitted to

United States Department of Energy

National Energy Technology Laboratory, Morgantown, WV
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DISCLAIMER

―This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government nor any agency thereof, nor any 

of their employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned 

rights. Reference herein to any specific commercial product, process, or service by trade 

name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency 

thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.‖

ABSTRACT

The project goal was to develop a cost-effective water recovery process to reduce the costs and environmental impact of shale gas production. This effort sought to develop both a flowback water pretreatment process and a membrane-based partial demineralization process for the treatment of the 

low-Total Dissolved Solids (TDS) portion of the flowback water produced during hydrofracturing operations. The TDS cutoff for consideration in this project is < 35,000 ~ 45,000 ppm, which is the typical limit 

for economic water recovery employing reverse osmosis (RO) type membrane desalination processes. 

The ultimate objective is the production of clean, reclaimed water suitable for re-use in hydrofracturing 

operations. 

The team successfully compiled data on flowback composition and other attributes across multiple 

shale plays, identified the likely applicability of membrane treatment processes in those shales, and 

expanded the proposed product portfolio to include four options suitable for various reuse or discharge applications. Pretreatment technologies were evaluated at the lab scale and down-selected 

based upon their efficacy in removing key contaminants. The chosen technologies were further validated by performing membrane fouling studies with treated flowback water to demonstrate the technical feasibility of flowback treatment with RO membranes. Process flow schemes were constructed 

for each of the four product options based on experimental performance data from actual flowback 

water treatment studies. For the products requiring membrane treatment, membrane system modeling software was used to create designs for enhanced water recovery beyond the typical seawater 

desalination benchmark. System costs based upon vendor and internal cost information for all process 

flow schemes were generated and are below target and in line with customer expectations. Finally, to 

account for temporal and geographic variability in flowback characteristics as well as local disposal 

costs and regulations, a parametric value assessment tool was created to assess the economic attractiveness of a given flowback recovery process relative to conventional disposal for any combination of 

anticipated flowback TDS and local disposal cost. It is concluded that membrane systems in combination with appropriate pretreatment technologies can provide cost-effective recovery of low-TDS flowback water for either beneficial reuse or safe surface discharge.
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ACKNOWLEDGEMENT

This material is based upon work supported by the Department of Energy, National Energy 

Technology Laboratory under Award Number DE-FE0000784

The authors would also to thank the following individuals: Dr. James Silva, GEGR for collaboration and consulting – Dr. Silva is the PI for the RPSEA 08122-36 investigating the treatment 

of NORM containing frac flowback waters. Steven Rice for conducting several membrane 

desalination experiments. Paul Wilson for setting up and trouble-shooting the complex 

membrane module testing setup. The GE Water Commercial team, including Mark Wilson, 

Todd Langford, Joseph Tinto, and Kyle Wendell for continuously updating market information 

and arranging for site-visits and contacts with gas-producers. Tom Hook and Preston Nelms 

for diligently acquiring frac flowback samples from Woodford and Fayetteville shales. Bill 

Walton and the GE Water Analytical team for the numerous water sample analyses. Larry 

Costa, David Polizzotti, Steve Vasconceles, John Piechel, Peter Ericksson, Tom Ciarra, and Irving Elyanow for their recommendations of water pretreatment and membrane systems, design and costing information, and the many reviews with very valuable feedback.
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Table of Contents

DISCLAIMER 2

ABSTRACT ....................................................................................................................................................................... 2

ACKNOWLEDGEMENT.......................................................................................................................................................... 3

Table of Contents.................................................................................................................................................................. 4

EXECUTIVE SUMMARY........................................................................................................................................................10

1 Project Narrative ................................................................................................................................................14

1.1 Project Objectives and Approach..................................................................................................................14

2 Budget...................................................................................................................................................................15

3 Results and Discussions...................................................................................................................................19

3.1 Task 1: Project management..........................................................................................................................19

3.2 Task 2: Obtain Flowback Attributes and Define Specifications for Water Re-use .........................19

3.2.1 Objectives and Approach ................................................................................................................................19

3.2.2 Water usage in shale gas exploration.........................................................................................................21

3.2.3 Definitions of various fluids used in shale gas exploration – Fracturing, Flowback/ Produced 

waters....................................................................................................................................................................21

3.2.4 Water Chemistry of the fracturing fluids used for shale gas exploration ........................................22

3.2.5 Flowback Attributes...........................................................................................................................................23

3.2.6 Summary of the flowback attributes ...........................................................................................................29

3.2.7 Flowback volumes amenable to ―Low-TDS‖ membrane-recovery.....................................................29

3.2.8 Flow volumes & flow rates ..............................................................................................................................30

3.2.9 Frac site visit........................................................................................................................................................31

3.2.10 Flowback samples .............................................................................................................................................31

3.2.10.1 Flowback rate profile ........................................................................................................................................32

3.2.10.2 Flowback Temperature: ...................................................................................................................................32

3.2.10.3 Flowback Water Composition........................................................................................................................33

3.2.11 Specifications for the frac flowback water recovery process ..............................................................42

3.2.11.1 Conventional Frac Flowback process..........................................................................................................42

3.2.11.2 Conventional water disposal ..........................................................................................................................42

3.2.11.3 Frac Flowback Recovery Process..................................................................................................................43

3.2.12 Technical specifications for recovery for frac re-use .............................................................................43

3.2.13 Summary of the verification of success criteria.......................................................................................50

3.3 Task 3: Define conceptual process alternatives for frac water recovery for re-use .....................52

3.3.1 Frac Flowback Water Recovery Process Options ....................................................................................52

3.3.2 Key contaminants in frac flowback of concern for reuse .....................................................................54

3.3.3 Considerations for evaluating technology & process options .............................................................55

3.4 Task 4: Evaluate key Pretreatment and Membrane Processes in bench-scale experiments.....58

3.4.1 Objectives and Approach ................................................................................................................................58

3.4.2 Bench-scale experimental approach ..........................................................................................................58

3.4.3 Process Step: ―Clarify‖.......................................................................................................................................59

3.4.3.1 Removal of Organics.........................................................................................................................................61
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3.4.3.2 Nature of the organics in frac flowback waters – novel analytical technique ...............................62

3.4.4 Process Step: ―Soften‖.......................................................................................................................................67

3.4.5 Desalination Membrane performance ........................................................................................................69

3.4.6 Process Flowsheets ...........................................................................................................................................70

3.4.7 Conclusions from Task 4: .................................................................................................................................71

3.5 Task 5: Obtain bench-scale experimental data suitable for process modeling .............................72

3.5.1 Objectives and Approach ................................................................................................................................72

3.5.2 Membrane performance parameters vs. Feed composition................................................................74

3.5.3 Evaluation of Desalination Membrane Fouling.........................................................................................77

3.6 Task 6—Develop system performance and cost models.......................................................................81

3.6.1 Objectives and Approach: ...............................................................................................................................81

3.6.2 Membrane Desalination Mobile Rig – FWRP costs & economical ―cut-off‖ TDS.............................82

3.6.3 Hybrid Membrane+Thermal Mobile system – FWRP costs & economical ―cut-off‖ TDS..............86

4 Summary and Conclusions .............................................................................................................................90

APPENDIX: Water Chemistry of Drilling and Hydrofracturing Fluids..................................................................93

Drilling fluid 93

Hydrofracturing Fluid ........................................................................................................................................................94

5 References ...........................................................................................................................................................98

List of Tables

Table 1. Water usage (average) per well and water requirements for the various shale plays (as 

estimated by Chesapeake Energy7) ..................................................................................................................................21

Table 2. Salinity of the flowback waters from various shales expressed in terms of Total Dissolved 

Solids (TDS). ....................................................................................................................................................................................30

Table 3. Compositions of the three 55-gal drums obtained from the Woodford shale that were used for 

bench-mark testing in Tasks 4 and 5...............................................................................................................................41

Table 4. The following specifications for re-use frac water in the Marcellus shale were apparently 

developed with data supplied by Halliburton and XTO Energy ........................................................................45

Table 5. Composition analyses for the Site-2 Day-26 waters: raw, pretreated by softening, and after 

24-hr membrane fouling test...............................................................................................................................................80

List of Figures

Figure 1 Simplified frac flowback water handling and disposal operation at a shale gas well site. ..........14

Figure 2. Conceptual Flowback Water Recovery Process (FWRP) for re-use in hydrofracturing..................15

Figure 3. Schedule and milestones for the program. ...........................................................................................................17

Figure 4. Task interrelationships and Go/No-go decisions. ..............................................................................................18

Figure 5. Flowback from a few wells in the Marcellus shale (Gaudlip et al). ...........................................................24

Figure 6 Flow rates vs. Flowback time for a few wells in the Marcellus shale (Gaudlip4). ................................25

Figure 7. Flowback rate vs. time for a Woodford shale (re-plotted from the data shown in Horn10)........25

Figure 8. Flowrate profiles for frac flowback from three Woodford shales............................................................26

Figure 9. Composition of a flowback sample from a Marcellus shale site (reproduced from Gaudlip4)..26
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Figure 10. Variation of flowback composition with time for a Marcellus shale site (reproduced from 

Gaudlip) ............................................................................................................................................................................................28

Figure 11. Variation of Sulfates and Ba/Sr concentrations as a function of flowback volume for a 

Haynesville shale ........................................................................................................................................................................28

Figure 12. Total Dissolved Solids (TDS) concentration profiles for flowback waters from a few Woodford 

shale wells ......................................................................................................................................................................................29

Figure 13. Photograph shows a saline water disposal (SWD) well co-located with three hydrofractured 

wells producing gas. .................................................................................................................................................................31

Figure 14. Profiles of the flowback water rate and water temperature are plotted vs. flowback time for 

the Site-1 in Woodford shale................................................................................................................................................32

Figure 15. Concentration profiles for Total Dissolved Solids (TDS) for the two Woodford frac sites...........33

Figure 16. Concentration profiles for Total Suspended Solids (TSS) and Turbidity for the two Woodford 

frac sites. .........................................................................................................................................................................................34

Figure 17. Concentration profiles for Hexane Extractables and Total Organic Carbon for the two 

Woodford frac sites. ..................................................................................................................................................................35

Figure 18. Concentration profiles for Total Hardness and Alkalinity for the two Woodford frac sites......36

Figure 19. Plot of Total Hardness (mg/l CaCO3) vs. Total Dissolved Solids (TDS) for the various frac 

flowback water samples collected from the two Woodford frac sites. .........................................................36

Figure 20. Profiles for the contributions of Calcium, Magnesium and Others (Fe, Sr, Ba) in terms of mg/l 

CaCO3 for the two Woodford frac sites..........................................................................................................................37

Figure 21. Concentration profiles for Barium, Strontium and Sulfate for the two Woodford frac sites. ..38

Figure 22. Concentration profiles for Iron, Manganese and Boron for the two Woodford frac sites.........39

Figure 23. Concentration profiles for Total and Reactive Silica for the two Woodford frac sites. ...............40

Figure 24. Photographs of vials containing frac flowback samples from Woodford shale Site-1 Days1-

14 and Site-2 Day-26................................................................................................................................................................41

Figure 25. Simplified frac flowback water handling and disposal operation at a shale gas well site. ......42

Figure 26. Conceptual Flowback Water Recovery Process (FWRP) for re-use in hydrofracturing...............43

Figure 27. Key contaminants in frac flowback water and their impact on re-use in hydrofracturing.....44

Figure 28. Summary of chemical characteristics of the waters used in conventional and blended 

Marcellus waters used for hydrofracturing by the Range Resources Company4....................................45

Figure 29. . Product Options for frac flowback water recovery. The target contaminants are listed for 

each process step in the respective boxes. The target contaminants to be removed in each 

process step are indicated inside the boxes................................................................................................................46

Figure 30. Specifications for the various Product Options described in Figure 29...............................................47

Figure 31. Plot of extent of product recovery, x as a function of the flowback water concentration and 

desired permeate product water concentrations when retentate concentration is limited to 

70,000 ppm TDS. .........................................................................................................................................................................48

Figure 32. Verification of success criteria for the Low-TDS frac flowback recovery process .......................51

Figure 33. Conceptual representation of a frac flowback recovery process to treat the frac flowback 

waters to provide the product options in Figure 30. The target contaminants to be removed in 

each process step are indicated inside the boxes....................................................................................................53

Figure 34. Technology options evaluated in the preliminary screening in Task 3 for removal of the 

various contaminants in frac flowback water. ...........................................................................................................57

Figure 35. Clarification of frac flowback waters. Results of bench-scale experiments with the 

―composite‖ Days 1-14 Woodford Site-1 sample......................................................................................................59

Figure 36. Clarification of frac flowback waters. Results of bench-scale experiments with the Day-26 

Woodford Site-1 sample.........................................................................................................................................................60

Figure 37. Clarification of frac flowback waters. Results of bench-scale experiments with the Day-1 

Woodford Site-1 sample.........................................................................................................................................................60

Figure 38. Clarification of frac flowback waters with coagulation and ultrafiltration. Results of benchscale experiments with the Site-1 Day-1 and Site-2 Day-26 Woodford samples. ..................................61

Figure 39. Removal of organics from Woodford shale flowback samples. Comparison of adsorption 

isotherms of three sorbents for the Site-1 Day-1 sample and ―Composite‖ Days 1-14 sample......62
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Figure 40. GCxGC-MS 2-D plots for the Control and Day-26 (frac) raw water. Note the presence of 

hydrocarbons of various polarities and boiling points (molecular weight) in the Site-2 Day-26 

sample. .............................................................................................................................................................................................63

Figure 41. GCxGC-MS 3-D plot for the Control methylene chloride (with 10 ppb methyl eiosonoate). ....64

Figure 42. GCxGC-MS 3-D plot for the Day-26 and Day-1 frac water field samples. Day-1 sample has 

more polar hydrocarbons and in general, higher intensities corresponding to the overall higher 

TOC content. ..................................................................................................................................................................................64

Figure 43. Effect of Treatment#1 on the organic contaminant levels of the Day-26 frac flowback water 

sample. Observe the appearance of peaks associated with surfactant molecules..............................65

Figure 44. Comparison of GCxGC-MS 2-D plots for Day-26 raw water and after Treatment#5 and 

Treatment#13...............................................................................................................................................................................66

Figure 45. Comparison of GCxGC-MS 3-D plots for Day-26 raw water and after Treatment#13 for two 

different times. .............................................................................................................................................................................66

Figure 46. Clarification of frac flowback waters with coagulation and ultrafiltration. Results of benchscale experiments with the Site-1 Day-1 and Site-2 Day-26 Woodford samples. ..................................68

Figure 47. Maximizing RO-desalination water recovery of pretreated Site-2 Day-26 flowback water via 

simulation studies using GE Winflows software20.....................................................................................................69

Figure 48. A conceptual process flowsheet for treating frac flowback waters to produce waters 

meeting Product-1 quality specs (cf. Figure 30). ........................................................................................................70

Figure 49. Operating cost breakdown for a 50 gpm mobile membrane rig capable of producing <500 

ppm TDS product........................................................................................................................................................................71

Figure 50. Membrane module testing rig for conducting desalination experiments with pretreated field 

frac flowback samples at GE Global Research. ..........................................................................................................73

Figure 51. Permeate TDS vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 liters of 

pretreated field frac flowback samples. See text for details..............................................................................75

Figure 52. Water flux parameter vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 

liters of pretreated field frac flowback samples. See text for details.............................................................76

Figure 53. Salt-flux parameter vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 liters 

of pretreated field frac flowback samples. See text for details. .......................................................................76

Figure 54. Salt-rejection parameter vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 

liters of pretreated field frac flowback samples. See text for details.............................................................77

Figure 55. Comparison of water-flux parameter change due to desalination membrane fouling for 

pretreated Site-1 Day-26 field frac flowback sample and pure NaCl/de-ionized water solution. ..78

Figure 56. Comparison of salt-flux parameter change due to desalination membrane fouling for 

pretreated "Day-26" field frac flowback sample and pure NaCl/de-ionized water solution..............79

Figure 57. Comparison of salt-rejection parameter change due to desalination membrane fouling for 

pretreated "Day-26" field frac flowback sample and pure NaCl/de-ionized water solution..............79

Figure 58. System configurations for the conventional frac flowback disposal via underground saline 

water disposal and the Flowback Water Recovery Process 50-gpm mobile rig under 

consideration in this project. ................................................................................................................................................81

Figure 59. Cost parameters, units and correlations for the FWRP & Conventional processes described 

in Figure 58.....................................................................................................................................................................................82

Figure 60. Mass balance profiles for membrane desalination based FWRP for Product-3 (20,000 ppm) 

and Product-4 (500 ppm)........................................................................................................................................................83

Figure 61. Cost components for the membrane-based FWRP: CRecovery, CConc_disposal and CFWRP for the 

operating and cost parameters developed in this project and for an assumed value of CDisposal...84

Figure 62. Cost of membrane-based FWRP vs. feed TDS concentrations forProduct-3 and Product-4 

quality specifications. ...............................................................................................................................................................85

Figure 63. Profiles for CFWRP/CConventional for the membrane system vs. Concentrate disposal costs 

at varying feed TDS concentrations. ................................................................................................................................86

Figure 64. Hybrid system incorporating pretreatment, membrane desalination and thermal distillation 

to yield Product-4 quality (500 ppm TDS); the 90K ppm TDS retentate from the membrane unit is 

distilled in the mobile evaporator to yield a 280,000 ppm TDS concentrate..............................................87
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Figure 65. Cost profiles for the Membrane system alone, Mobile evaporator alone and the Hybrid 

membrane+thermal systems as a function of feed TDS concentration. ......................................................88

Figure 66. Profiles for CFWRP/CConventional ratio vs Concentrate disposal costs for varying feed TDS 

concentrations. ............................................................................................................................................................................89

Figure 67. Volumetric composition of a representative hydraulic fracturing fluid excluding the 

proppants (reproduced from D. Arthur et al., ALL Consulting25). .......................................................................95

Figure 68. Additives in the hydrofracturing fluid ...................................................................................................................96

Figure 69. Additives used in the hydrofracturing fluid, as reproduced from information published by 

Talisman Energy, Inc28..............................................................................................................................................................97
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List of Acronyms

Acronym Definition

bbl Barrel (1 bbl = 42 gallons)

Conventional Conventional Flowback Water Disposal Process based on Class II SWD

CChemicals Cost of process chemicals, $/bbl flowback

CConventional Cost of Conventional Flowback Water Disposal Process, $

CDisposal Cost of flowback disposal (= CTransport + CSWD), $/bbl

CFWRP Cost of Flowback Water Recovery Process, $

CFresh Water Cost of fresh water for frac use, $/bbl

CMaintenance Cost of annual maintenance per annual feed processed, $/bbl flowback

CPenalty_Avoid Value of penalty avoided due to flowback re-use

CProcess Cost of process steps (capital and operating expenses), $/bbl feed

CProduct Delivery Cost of product delivery to re-use site, $/bbl product 

CProduct_Value Value of fresh water avoided due to flowback re-use, $/bbl product

CRecovery Cost of product recovery (= CTreatment + CProduct Delivery – CProduct_Value+CPenalty_Avoid), 

$/bbl product

CSWD Cost of saline water disposal by deep well injection, $/bbl

CSetup Cost of mobile rig transportation and setup at the frac site, $/bbl feed

CTreatment Cost of flowback treatment to produce product (=CSetup + CProcess), $/bbl feed

CTransport Cost of transportation of disposal water, $/bbl flowback or concentrate

CWaste Cost of FWRP process waste disposal, $/bbl flowback

―Cut-off‖ TDS The value of yF where the CFWRP/CConventional = 1 represents the economical 

―cut-off‖ TDS for that particular frac flowback site. 

F Flowback volume, bbls

FWRP Flowback Water Recovery Process

GE General Electric

GEGR General Electric Global Research

GEW&PT General Electric Water & Process Technologies

MF Microfiltration

MMcf Million cubic feet

NF Nanofiltration

NTU Turbidity measurement unit

RO Reverse Osmosis

SWD Saline water disposal – deep injection Class II well

SRB Sulfate reducing bacteria 

TDS Total Dissolved Solids

TSS Total Suspended Solids

UF Ultrafiltration

X Extent of flowback recovered, bbl product/bbl flowback

XPretreatment Extent of flowback recovered after pretreatment prior to membrane desalination), bbl/bbl flowback

yF Feed TDS concentration, ppm

yConcentrate Concentrate (sent to SWD) TDS concentration, ppm

yDistillate Distillate (from thermal evaporator) TDS concentration, ppm

yPermeate Permeate (from membrane) TDS concentration, ppm

yProduct Product TDS concentration, ppm

yRetentate Membrane retentate (reject) TDS concentration, ppm
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EXECUTIVE SUMMARY

This is the final report for this project supported by U.S. DOE NETL (Contract No. DE-FE0000784) and GE 

Global Research (GEGR). This report provides a project narrative and a summary of project activities 

and accomplishments for the reporting period, beginning October 1, 2009 and ending March 30, 2011. 

The project goal was to develop a cost-effective water recovery process to reduce the costs and environmental impact of shale gas production. This effort sought to develop both a flowback water pretreatment process and a membrane-based partial demineralization process for the treatment of the 

low-Total Dissolved Solids (TDS) portion of the flowback water produced during hydrofracturing operations. The TDS cutoff for consideration in this project is < 35,000 ~ 45,000 ppm, which is the typical limit 

for economic water recovery employing reverse osmosis (RO) type membrane desalination processes. 

The ultimate objective is the production of clean, reclaimed water suitable for re-use in hydrofracturing 

operations. 

Over the past year, the shale gas industry appears to be continuously evolving in terms of methodologies and technologies used for hydrofracturing. Moreover, the various States have been active on the 

regulatory front in terms of water sourcing and disposal for this very important energy sector. It was 

necessary to understand this dynamic nature of the shale gas market and the potential impact that 

has on the specifications and costs for our product water for frac re-use. The team reviewed information published in open literature and obtained feedback from frac operators. The team also visited 

frac flowback and underground injection disposal sites to get a better understanding of the operation 

logistics and specifications for water re-use. 

Consequently, it became necessary to update the product water scope from the one product with 

20,000 ppm TDS initially proposed to potentially four alternative products with varying levels of purification:

 Product-1: Clarified only (removal of suspended matter, free oil & grease, Fe, and microbiological contaminants)

 Product-2: Softened and Clarified (removal of hardness ions, namely Ba, Sr, Ca, Mg besides the 

purity specs for Product-1)

 Product-3: Partially desalinated to < 20,000 ppm TDS (besides the purity specs for Product-2)

 Product-4: Substantially desalinated to < 500ppm TDS (besides the purity specs for Product-2). 

Product-3 above now represents the initial product target.

For this project, the verification of success criteria for critical go/no-go decisions were determined to 

be:

 Product quality specifications for the Products 1-4 to their respective target applications. Water recovery >95% for Product-1 and >90% for Product-2. For flowback water with <40,000 

ppm TDS, water recovery > 50% for Product-3 and > 40% for Product-4. 

 Cost of the overall Flowback Water Recovery Process (FWRP) < Cost of Conventional Saline 

Water Disposal. The FWRP includes Treatment Costs (mobile rig related process equipment, 

transportation & setup, chemicals and waste disposal, power) and Concentrate Disposal 

Costs. For the shale plays under consideration, this translates to target Treatment Cost < 

$2/bbl flowback water.
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 Separation process operable in a 50-gpm mobile rig configuration

Information on frac flowback attributes (flow rate vs. time and corresponding water analysis) is not 

readily available, as frac operators tend to keep their data proprietary and confidential. Nevertheless, 

relevant information on the flowback and produced waters in the Marcellus, Haynesville, Barnett, 

Fayetteville, and Woodford shales was acquired, albeit under non-disclosure agreements. 

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 shale 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 components in the flowback water of interest in this project are particulates (>5 μm), suspended solids (<5μm, colloids), free oil, dissolved organics, volatile organics, hardness ions (Ca, Mg, Ba, 

Sr, sulfates, carbonates), Fe, silica, and bacteria that may affect the product quality and/or the desalination membrane performance. 

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 15~40%, but could be higher in certain wells.

Based on surveys of the TDS content of the flowback waters from the different shales, the team‘s present view on the extent of applicability of our low-TDS (< 40,000 ppm) recovery approach is as follows: 

In Fayetteville and Woodford, almost 90-100%, since the flowback has generally < 40,000 ppm TDS. In 

Barnett, by selectively directing the flowback from the first 5 days, ~30-40% of the flowback may qualify as low-TDS, but recovery may not be considered at all since disposal via underground injection is 

readily and cheaply available. In Marcellus, overall only a small fraction (<10%) of the flowback may be 

amenable to low-TDS recovery. However, 10–20% of the flowback may be amenable at certain locations with appropriate water management to isolate the first 3~5 days of flowback water. In the 

Haynesville shale, due to the high TDS salinity and the availability of saline water disposal sites in East 

Texas, there is limited scope for membrane-based frac flowback recovery. 

Frac flowback samples were obtained from wells in the Woodford shale in Oklahoma. These are daily 

samples from Day-1 through Day-14, along with two 55-gal drums of water samples from Day-1 and a 

composite of several daily samples. Another 55-gal drum sample was obtained from the Day-26 flowback from another nearby well. These water samples were used in experiments for assessing pretreatment and membrane options.

Bench-scale experiments have been successful in identifying process technologies and associated 

operating conditions for the removal of key contaminants pursuant to the product quality specifications for the alternative Products-1, -2, -3 and –4. However, removal of organic contaminants proved 

to be a greater challenge for frac flowback waters than anticipated. This was solved with use of a 

novel ultrafiltration membrane. A novel analysis technique developed by Hans Grade at GE Global 

Research that uses a 2-column gas chromatography (GC) method for separation of the components 
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based on polarity and boiling point, followed by analysis with a Time of Flight Mass Spectrometer, was 

applied to understand the nature of organics in frac flowback water samples. This technique was 

found useful in providing a qualitative understanding of the effect of pretreatment methods on the 

presence and disappearance of organic compounds in the treated frac flowback waters. 

For Products-3 and –4 that require RO membrane desalination, key membrane foulants, namely inorganic compounds that could physically precipitate inside the membrane module and inorganic and 

organic contaminants that could foul the membrane surface, were shown to be successfully removed 

in in these bench-scale experiments. For demonstration, RO membrane fouling experiments were 

conducted using commercially available 2‖ diameter spiral wound RO modules with 10 liters of pretreated Woodford Site-2 Day-26 35K ppm TDS flowback sample over 24 hours at 800 psig & 25C. The 

water-flux and salt-rejection vs. time profiles for this run were identical to those for a similar run with a

―control‖ solution of 35K ppm TDS NaCl in deionized water. This indicated the effectiveness of the 

down-selected pretreated conditions in removal of potential membrane foulants.

For Product-3 and Product-4, various membrane system configurations were evaluated and optimized 

via performance modeling with GE Winflows software to increase water product recovery. For a feed 

solution composition similar to that obtained after pretreating (lime softened and filtered) Site-2 Day26 sample, the identified configurations increased the recovery from 49% for a standard seawaterdesalination design to as high as 61.5%. The maximum retentate concentration correspondingly increased from 68K ppm to 90K ppm TDS for these conditions. The increase in capital costs due to additional pumps, membrane modules, interconnected piping and controls for the new configuration were 

more than offset by the increased water recovery when the overall Flowback Water Recovery Process 

(FWRP) was considered.

Using the information from the bench-scale experiments for the various pretreatment steps, detailed 

conceptual flowsheets for the treatment processes were constructed for each of the Products 1-4 under consideration. These were evaluated for technical performance, costs and mobility for a 50-gpm 

feed (frac flowback) mobile rig system. Technical performance evaluation included mass and energy 

balances, including waste generation and handling. Costs included capital expenses for equipment 

and assembly and operating expenses for amortization of capital equipment, rig transportation and 

labor for rig-setup, chemicals, membranes, power, and waste removal. The cost estimations were 

based on reliable values obtained either from vendors or internal cost information for the desired 

equipment. Mobility included the preliminary assessment of the rig configurations and footprint suitable to treat 50 gpm of the frac flowback water. 

The Treatment Cost target of <$2/bbl was satisfied for all product options, in line with preliminary 

feedback on customer expectations. For the 50-gpm mobile rig configuration, the ―fixed‖ expenses 

(capital-related costs, rig transportation & setup, maintenance) dominated the Treatment Costs at 

~75% followed by chemicals & solids waste disposal at 18%, while the costs of replacement membranes and electrical power were only 2% and 5%, respectively

A value-assessment cost model was developed for the overall FWRP for the Products -3 &-4 that use 

RO membrane desalination to compare with the conventional disposal method. The conventional disposal cost included transportation of all flowback water and injection in Class II SWD wells while the 

FWRP cost included treatment costs, product delivery and remaining concentrate disposal (transport + 

SWD injection) costs. The sensitivities of the FWRP cost to prevailing concentrate disposal conditions 

were expressed as plots of CFWRP/CConventional vs. CDisposal at different feed TDS concentrations. The eco-
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nomical ―cut-off‖ TDS is defined as that feed TDS concentration when CFWRP/CConventional =1. For Product4 (500 ppm TDS), this ―cut-off‖ TDS is in the range of 20,000 ppm to 65,000 ppm depending on the local 

saline water disposal costs. These sensitivity charts thus provide a means of comparing the relative 

value of FWRP for a well flowback treatment opportunity based on prevailing disposal costs and anticipated flowback TDS levels. Note that the other drivers, such as penalty avoidance or cost incentives 

due to frac flowback re-use due to local regulations have not been considered. In some cases, these 

non-technical issues may be the economic driver for FWRP.

To increase the overall system water recovery, a Hybrid membrane + thermal system was also considered. In this approach, the retentate (90,000 ppm TDS) from the membrane system is further concentrated by distillation in a mobile evaporator (such as that introduced by GE Water recently22) to yield a 

distillate with <500 ppm TDS but more importantly, a concentrate with 280,000 ppm TDS. The Hybrid 

system yields higher recovery; for example, 85% for a feed with yF = 35,000 ppm TDS vs. 61% for the 

membrane rig alone. However, the Hybrid process costs more than individual process options alone 

due to the high fixed costs for such small throughput (50 gpm) systems. The sensitivity plots of 

CFWRP/CConventional vs. CDisposal at different feed TDS concentrations show the dramatic decrease in CFWRP

for the Hybrid due to increased water recovery. The Membrane alone case is more economical for the 

lower CDisposal cases mainly due to the lower overall capital costs. However, the Hybrid case becomes 

more economically attractive for the high CDisposal (>$5/bbl) shale plays where local SWD sites are unavailable, thus leading to higher flowback water transportation costs for the conventional disposal 

method. 

It is concluded that membrane systems in combination with appropriate pretreatment technologies 

can provide cost-effective recovery of low-TDS frac flowback water for either beneficial reuse in hydrofracturing or safe surface discharge.
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1 Project Narrative

1.1 Project Objectives and Approach

Two significant barriers to the development of many shale gas plays are water availability for 

drilling and hydrofracturing and disposal options for the water coproduced with gas ("frac 

flowback water"). In this project, GE Global Research (GEGR) evaluated technology that reduces the cost of treating flowback water for re-use in the hydrofracturing process. 

The principal goal of this project was to define a mobile, cost-effective membrane-based 

process to treat low-TDS frac flowback water for re-use as hydrofracturing fluid. The TDS 

cutoff for consideration in this project is < 35,000 ~ 45,000 ppm, which is the typical limit for 

economic water recovery employing reverse osmosis (RO) type membrane desalination processes. 

The conventional frac flowback water handling process, although quite complex in terms of 

the safety and operational logistics, is shown simplified for our purposes in Figure 1. The 

flowback water is directed to a separator to separate the water from the gas and the solid 

proppants. The flowback water is stored in interim storage tanks and then trucked to water 

disposal sites, typically Class II deep saline water disposal sites (SWD). At initial flowback 

rates, typically 100~150 bbl/hr, this translates to roughly one truck/hour for the first 5-10 

days of flowback. This has implications for traffic, road infrastructure and noise pollution, as 

well as the loss of water from useful surface applications.

A conceptual process considered in this project for recovering all or part of the flowback water for re-use in hydrofracturing operations is shown in Figure 2. The flowback water recovery process (FWRP) is desired to be located physically close to the well operations to minimize 

water hauling costs. It includes a mobile unit equipped with the necessary treatment operations to provide ―product‖ water that meets specifications for re-use in hydrofracturing. Only 

Figure 1 Simplified frac flowback water handling and disposal operation at a shale gas well site.

Conventional Flowback Water Disposal Process

Interim 

Flowback 

Water 

Storage

Saline Water 

Disposal

120 bbl/truck

Ctransport : $2~$20/bbl

Flowback

water

Gas for sales

Proppant

Well head

For deep well injection: 

CSWD : $1 ~ $3/bbl

CDisposal = CTransport + CSWD ($/bbl water)
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a portion of the flowback water may be recovered as product, while the rest may have to be 

disposed of either in conventional saline water disposal Class II wells or via further recovery 

by methods suitable for desalination of high-TDS waters (> 80,000ppm), such as thermal processes.

Flowback Water Recovery Process for Frac R e-use

Flowback

water

Interim 

Flowback 

Water 

Storage

Ctransport : $2 ~ $20/bbl

R e-use 

water site

Fractional Recovery = X

CTreatment $/bbl

For deep well injection: 

CSWD : $1 ~ $3/bbl

High TDS reject

“product”

Re-use quality water

Gas for sales

Proppant

Well head Saline Water 

Disposal

CRecovery = CTreatment + Cdelivery ($/bbl product)

CDisposal = CTransport + CSWD ($/bbl reject)

CFWRP = X CRecovery + (1-X) Cdisposal ($/bbl flowback)

CDelivery $/bbl

Flowback Water 

Recovery Process

The overall cost will depend on the extent of water recovery, x, in the FWRP.

The chief benefits are greatly reduced fresh water consumption, up to 50% less watertransportation related traffic on roads, reduced water disposal costs, and a greatly reduced 

impact on the environment. 

2 Budget

Figure 2. Conceptual Flowback Water Recovery Process (FWRP) for re-use in hydrofracturing.
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Total funding for this program was approximately $1 MM including a 20% cost share contributed by GE Global Research, as seen in Table 1. Quarterly variances in spending were due to 

initial non-availability of frac flowback water samples. However, these mismatches were fully 

accounted for by the end of the program. Table 1 indicates that the program was underspent by $65K at the end of March 2011. However, final report and report-out is anticipated 

to bring this number to about $20K which is within 2% of the original budget amount.

This project was organized into six interrelated tasks including:

 Project Management Plan 

 Obtain flowback attributes (flow rate and composition profiles vs. time) and define 

specifications for water re-use 

 Define conceptual process alternatives for low-TDS water recovery for re-use

 Evaluate key pretreatment and membrane processes in bench-scale experiments

 Obtain bench-scale experimental data suitable for process modeling

 Develop system performance and cost models for a mobile rig configuration of the 

downselected process to determine the commercial feasibility of the overall process 

for low-TDS flowback water recovery for reuse. 

The project timeline and a task interrelationship chart summarizing the logic that connects 

the various tasks are shown in Figure 3 and Figure 4. 

Q1 Total Q2 Total Q3 Total Q4 Total Q1 Total Q2 Total

Baseline Cost Plan

Federal Share 131,587 131,587 132,825 264,412 179,065 443,477 184,598 628,075 76,560 704,635 76,209 780,844

Non-Federal Share 32,897 32,897 33,206 66,103 44,766 110,869 46,150 157,019 19,140 176,159 19,052 195,211

Total Planned 164,484 164,484 166,031 330,515 223,831 554,346 230,748 785,094 95,700 880,794 95,261 976,055

Actual Incurred Costs

Federal Share 68,328 68,328 163,173 231,500 149,290 380,791 97508 478,299 104,443 582,742 145,448 728,190

Non-Federal Share 17,082 17,082 40,793 57,875 37,323 95,198 24377 119,575 26,111 145,685 36,362 182,047

Total Incurred Costs 85,410 85,410 203,966 289,375 186,613 475,988 121,885 597,873 130,554 728,427 181,810 910,237

Variance

Federal Share (63,260) (63,260) 30,348 (32,912) (29,775) (62,686) (87,090) (149,777) 27,883 (121,894) 69,239 (52,654)

Non-Federal Share (15,815) (15,815) 7,587 (8,228) (7,444) (15,672) (21,773) (37,444) 6,971 (30,473) 17,310 (13,164)

Total Variance (79,074) (79,074) 37,935 (41,140) (37,218) (78,358) (108,863) (187,221) 34,854 (152,367) 86,549 (65,818)

10/1/'09 - 12/31/'09 1/1/'10 - 3/31/'10 4/1/'10 - 6/30/'10 7/1/'10 - 9/30/'10 10/1/'10 - 12/31/'10 1/1/'11 - 3/31/'11

COST PLAN/STATUS

Baseline Reporting 

Quarter

Year 1 Year 2

Q1 Q2 Q3 Q4 Q1 Q2
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Program Activities Q1 Q2 Q3 Q4 Q1 Q2

Milestone: Updated Project Management Plan completed

Technology Status Summary

Quarterly, annual, and final reports.

Frac flowback water flowrate & composition profiles for 1 or 2 shale-gas sites 

available

Specifications for recovered water for re-use as frac water obtained.

Field water samples for bench-scale testing acquired

Potential membrane processes with associated pretreatment technologies 

identified

Preliminary process and cost models for alternatives developed

Range of cost estimates for low-TDS water recovery completed

Decision Point: Go/no-go decision on Low-TDS frac water recovery feasibility (based on 

performance/cost assumptions)

Pretreatment: test setup, validation and testing with field flowback water 

samples

Membrane: test setup, validation and initial testing with field flowback water 

samples

Key known membrane foulants in frac flowback water identified and 

successfully removed

Decision Point: Go/no-go decision based on preliminary cost estimates of effective 

pretreatment process

Milestone: Experimental data for key pretreatment and membrane processes with field 

frac flowback water

Detailed process configuration modeling for low-TDS water recovery based on 

bench-scale experimental data.

Technical feasibility of low-TDS frac flowback recovery process to produce 

water for frac re-use 

Cost modeling for mobile unit with technically feasible process for low-TDS flow 

back water recovery 

Determination of “cut-off” point for low-TDS water recovery process for 

commercial shale-gas drilling operations.

Deliverable: Technical report summarizing downselected low-TDS frac water recovery 

system configuration and cost estimate including supporting bench-scale 

experimental data

Decision Point: Go/no-go decision on final process configuration to meet performance and cost 

targets

Legend: Deliverable Milestone Critical Path Milestone 

Milestones: 

Deliverables: 

Milestones: 

Task 1: Project Management Plan

Task 2: Obtain Flowback Attributes and Define Feed & Product Specs for water re-use

Task 4: Evaluate key Pretreatment & Membrane Processes in bench-scale experiments

Task 5: Obtain bench-scale experimental data suitable for process modeling

Task 6: Develop system performance and cost models

Milestones: 

Milestones: 

Project Duration

Start: October 1 2009

End: March 31 2011

PY 1 PY 2

Task 3: Define conceptual process alternatives for low-TDS water recovery

Figure 3. Schedule and milestones for the program.
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1 /

GE Title or job number /

5/3/2011

Task2 -Obtain flowback attributes and 

define Feed & Product Specs for water reuse

• Frac flowback water profiles from 1 or 2 

shale-gas sites

• Specifications for recovered water for reuse as frac water

• Field water samples for bench-scale testing

Task3 -Conceptualize process alternatives 

for low-TDS water recovery & obtain 

initial cost estimates

• Potential pretreatment & membrane 

processes technologies

• Preliminary process and cost models for 

alternatives

• Range of cost estimates for low-TDS water 

recovery

Year1H1 Go/no-go:

Will processes 

potentially provide 

product water suitable 

for re-use in frac?

Does estimated cost 

meet cost targets?

END 

PROGRAM

Task4 -Evaluate downselected pretreatment & 

membrane processes in bench-scale 

experiments

• Pretreatment: test setup and testing with field 

flowback water

• Membrane: test setup and testing with field 

flowback water

• Key known membrane foulants identified and 

successfully removed

Task6 -Develop system performance and cost 

models of low-TDS frac flowback recovery 

process for re-use in frac

• Detailed process modeling based on benchscale experimental data

• Technical feasibility analysis 

• Cost model for mobile unit with technically 

feasible process

• Determination of “cut-off” point for low-TDS 

water recovery process for commercial shalegas drilling operations

No

Yes

Program success:

Does process 

configuration of 

low-TDS flowback

water recovery 

meet performance 

and cost targets?

Proceed to 

pilot 

developmen

t phase

Yes

Task5 -Obtain bench-scale experimental data 

suitable for process modeling

• Experimental data for key pretreatment and 

membrane processes with field frac flowback 

water

Year1H2 Go/no-go:

Does pretreatment 

process remove known 

membrane foulants, 

cost-effectively? Yes

No

Figure 4. Task interrelationships and Go/No-go decisions.
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3 Results and Discussions

3.1 Task 1: Project management

This program delivered 5 technical progress reports, one at the end of each quarter of this 

project. A Technology Status Assessment analyzing the most advanced examples of the proposed technology was completed and a report was issued. In addition, at the end of budget 

period (BP) 1 an annual report on project accomplishments for continuation of funding was 

submitted. The team presented work done for the project at the 2010 Ground Water Protection Council Annual Meeting, Pittsburgh, PA, Sep 26-281 and the Canadian Society of Unconventional Gas Water Workshop, April 20, 20112

. Additionally, presentations were made to 

potential customers to educate and highlight potential solutions to frac flowback and produced water recovery.

3.2 Task 2: Obtain Flowback Attributes and Define Specifications for Water 

Re-use

3.2.1 Objectives and Approach

The specific objectives of this task were to: 

 Understand frac flowback operations and estimate the amount of flowback that 

qualifies as ―low-TDS‖ water suitable for recovery via membrane processes

 Define performance and cost specifications, and develop the verification of success 

criteria for assessing the water recovery processes considered in this project.

The key activities were to: 

 Obtain frac flowback water attributes (composition and flow rate profiles over time) 

 Obtain specifications for ―product‖ water that would be re-used for hydrofracturing.

We reviewed information published in open literature, discussed with frac operators, and visited a frac flowback site to get a better understanding of the actual operation logistics. 

There have been several barriers to obtaining reliable information on the water chemistry 

used for hydrofracturing, flowback attributes, and specifications for the re-use water, including:

 The water chemistry used for hydrofracturing depends on the geology of the shale 

formation and the technology bias/experience of the operator. Thus, there could be 

variation in the water chemistry between different shales, within different sites within 

the same shale and between different services companies operating in the same 

shale. Moreover, the methods used for hydrofracturing are being continuously updated as the industry tries to optimize operations to maximize gas recovery while 

minimizing energy and especially, fresh water usage3. For example, current research 
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on new slicking agents (friction reducers) may allow the use of higher salinity in the 

feed water compared to present operations.

 Information on frac flowback attributes (flow rate vs. time and corresponding water 

analysis) is not readily available, as frac operators tend to keep their data proprietary 

and confidential. There is very limited published data on the flowback attributes for 

the various shales. 

 Opinions vary widely on the water quality that may be used for hydro-fracturing. For 

instance, some of the operators insist on using very low-TDS source water to avoid 

scaling issues in the downhole piping, while others, such as Range Resources, have 

reported some success in using a 26,000 ppm Chlorides water feed in the Marcellus 

shale4. Some experts feel that water salinity equivalent to seawater, namely ~ 35,000 

ppm TDS may be usable for hydrofracturing5. Some operators are considering the 

use of even salinity as high as 120,000 ppm TDS with low hardness and scale-causing 

contaminants6. As a practical matter, the relative costs for drilling and hydrofracturing a well are in the neighborhood of $1million each, while water costs for 100,000 

bbls, when available, are in the neighborhood of $25,000. The risks associated with 

scaling and well-plugging due to ―unclean‖ water used for hydrofracturing may not 

be tolerable to many operators. Hence, it appears that the move towards higher TDS 

water used to stimulate gas wells is being driven by state and regional water availability, the logistics of flowback water transportation and disposal costs, and also the 

desire to mitigate negative public perception about water use for hydrofracturing 

and groundwater pollution.

 Regulations are being considered by various federal and state agencies on the disclosure of chemistry used for the hydrofracturing process, discharge of flowback water, and the re-use of flowback water for hydrofracturing. Until the regulations are finalized, there will be uncertainty on the specifications for the treated water and discharge water. This affects the determination of how much of the flowback water 

would qualify as ―low-TDS‖ suitable for membrane treatment, the choices of technology options useful to treat the frac flowback water to meet the technical specifications, and the overall system cost.

The conclusion from our survey was that the specification for acceptable re-use is subject to 

change in the short-term depending on technology advances that are continuously occurring, operator experience and confidence, and upcoming regulations regarding discharge 

and re-use.

Nevertheless, we were able to find relevant information on the flowback and produced waters in the Marcellus, Haynesville, Barnett, Fayetteville and Woodford shales. Some of this data was acquired under non-disclosure agreements and will only be summarized as appropriate in the following sections.
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3.2.2 Water usage in shale gas exploration

The main uses for water in deep shale exploration are: 

 Drilling, where a mixture of clay and water is used to carry rock cuttings to the surface, as well as to cool and lubricate the drill bit. 

 Hydrofracturing (or ―frac‖), where a mixture of water and sand is injected into the 

deep shale at a high pressure to create small cracks in the rock and allow gas to 

freely flow to the surface. 

Typical average usage of water for drilling and frac operations for the Barnett, Fayetteville, 

Haynesville and Marcellus shales, as estimated by Chesapeake Energy Company7 are shown 

in Table 1.

Table 1. Water usage (average) per well and water requirements for the various shale plays (as 

estimated by Chesapeake Energy7)

According to Chesapeake Energy, a deep shale gas well will produce between 2 and 6.5 Bcf 

(billion cubic feet) over its lifetime. Thus, the amount of water used to produce the gas 

equates to about 0.8 to 1.7 gallons/MMBTU or 19 to 40 bbls water/MMcf of gas (assuming 

1,000 scf of gas is equivalent to 1 MMBTU of energy)8.

3.2.3 Definitions of various fluids used in shale gas exploration – Fracturing, Flowback/ 

Produced waters

The fluid that is used to stimulate the shale gas formation during hydrofracturing is generally 

referred to as ―Fracturing Fluid‖ or ―Completion Fluid‖. The fluid that flows back after a hydrofracturing operation is referred to either as ―flowback‖ water or ―produced‖ water. There is 

some confusion on the strict definitions and differences between the two terms. In conventional oil & natural gas fields and in coal bed methane reservoirs, there is an excess of water 

in the formation that comes up to the surface during oil and gas production. This water has 

traditionally been referred to as ―produced water‖. In fact, during oil production, it is estimated that approximately 7 bbls of water are produced for every bbl of oil9

. However, in shale 

gas exploration, typically, most of the water that flows back is the water that was fed during 

the hydrofracturing operation. 

According to Horn10, when the flowback volume reaches 100% of the fracturing fluid volume, 

it is then subsequently referred to as ―produced water‖. However, our survey11 of gas proDrilling Fracturing Total

Barnett 10,000 70,000 80,000 600 48

Fayetteville 1,500 70,000 71,500 250 18

Haynesville 25,000 65,000 90,000 200 18

Marcellus 2,000 90,000 92,000 600 55

Water used (average), bbls/well Wells/year Water

 MM bbls/year
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ducers appears to indicate that the rationale for referring to the water as ―flowback‖ or ―produced‖ could be any of the following: 

1. Financial: Water produced during the well completion stage is defined as flowback 

and the associated costs are part of the well completion budget. When the well is 

considered to be under ―gas production‖ the water is called ―produced‖, and the associated costs are part of the "operating" budget.

2. Time: Some companies use a time factor, for example 30 days as the demarcation 

between ―flowback‖ and ―produced‖. Typically, the flow rate has dropped off significantly during this period.

3. Volume: Some producers differentiate based on how much they get back as a percent of fracturing fluid put down into the well. It may be 100% as per the definition 

provided by Horn10 or less, as per the operator‘s choice. However, in shale gas wells, 

the overall water flowback could be < 50% of the fracturing fluid used, typically only 

25-35% in the first 30 days.

It appears that the financial reason appears to be the most commonly used definition to differentiate between ―flowback‖ and ―produced‖ waters. 

In any case, for shale gas wells, from a flow rate perspective, the flow rates during the ―flowback‖ phase are significantly larger (by 10-100x) than in the ―produced‖ phase. From a 

chemical perspective, the produced water has higher concentrations of the various minerals 

because of the greater residence downhole, whereas the flowback water may contain higher 

amounts of suspended solids, oils, fuels and chemicals associated with the drilling and hydrofracturing operations. However, for some shales, the chemical characteristics during the 

flowback phase may have already approached those at the produced phase of the operation 

(depending on the definition chosen by the operator). 

In this report we do not differentiate between the two definitions and refer to all returning 

water after a hydrofracturing event as ―flowback‖ for evaluation of our recovery process options.

3.2.4 Water Chemistry of the fracturing fluids used for shale gas exploration

It is important to know the composition of the fluid used for drilling and hydrofracturing since 

the flowback water may contain some or all of these chemicals besides the contaminants 

from the soil and shale layers.

Drilling fluids:

The composition of the drilling fluids used depends on the geology of the shale formation and 

the technology bias/experience of the operator. Most of the information is held proprietary 

and confidential. However, a good summary of the various components is provided at the 
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DOE NETL website12. Relevant information for this project is summarized in Appendix A. 

From the flowback water treatment perspective, the key components that could be considered as contaminants during recovery are: 

 ―oil‖ in the oil-based muds. These are most likely diesel. In fact, the Day-1 sample of 

flowback water obtained by the team has a diesel-like odor. Apparently, at some locations, after drilling, the equipment are cleaned with diesel, although this practice 

may be discontinued in the future13.

 olefins, esters, linear alpha-olefins, poly alpha-olefins, linear paraffins, etc. in the synthetic-based muds, if used.

Frac fluids:

Fracturing fluids used for fracturing gas shales include a variety of additive components, 

each with an engineered purpose to facilitate fractures and the production of gas3(see Appendix for details). Currently, the trends in shale wells are to use water based or mixed slickwater-fracturing fluids. These are water‐based fluids mixed with friction reducing additives14

, 

which allows a fracturing fluid and proppant to be pumped to the target zone at a higher rate 

and reduced pressure than by using water alone. In addition, other additives including biocides are utilized to prevent micro‐organism growth and to reduce bio‐fouling of fractures. Of 

particular concern are the sulfate reducing bacteria (SRB) as they reduce sulfate ions to hydrogen sulfide; H2S causes corrosion in the downhole pipeline and at higher concentrations 

(> 4 ppmv) may cause sourness issues with the sales gas. Oxygen scavengers and other stabilizers which prevent corrosion of metal pipes and acids which are used to remove drilling

mud damage near the wellbore area are also common either in fracturing fluids or as part of 

fracture treatments. 

Details of the various components in the hydrofracturing fluid are provided in Appendix. 

From the flowback water treatment perspective, although it is expected that some or all of 

these additives may be expected in the flowback, no literature reports confirming the presence and concentrations of these additives could be found. It is likely that these compounds 

may get chemically, physically or microbiologically altered or destroyed during the hydrofracturing process or become lost in the shale formation. Although some of these additives, such 

as guar gel, polyacrylamides, and petroleum distillates, may affect membrane performance,

the actual impact would have to be experimentally determined with flowback water samples. 

3.2.5 Flowback Attributes

Information on frac flowback attributes (flow rate vs. time and corresponding water analysis) 

is not readily available, as frac operators tend to keep their data proprietary and confidential. 

There is very limited published data on the flowback attributes for the various shales. Nevertheless, we were able to find relevant information on the flowback & produced water attributes for the Marcellus, Haynesville, Barnett, Fayetteville and Woodford shales. Most of this 
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data was acquired under non-disclosure agreements and will only be summarized, as appropriate in the following sections. 

Flowback Flow rates

For the Marcellus shale, Gaudlip4 has reported flowback volumes over a period of 14 days for 

a few wells, as reproduced in Figure 5. 

Figure 5. Flowback from a few wells in the Marcellus shale (Gaudlip et al).

We make the following observations:

 The % recovery, i.e. the volume of water that flows back as a % of the fracturing fluid 

fed during the hydrofracturing process is between 19% to 29% at the 14-day mark. A 

general rule of thumb is that ~25% recovery is the expected norm in the Marcellus 

shale during the initial phase of the flowback, generally regarded as the first 30 

days11.

 The flowback rate is highest initially and then decreases. This is illustrated in Figure 6. 

For the first few days, the flow rates could be in the high range of 2,500 to 6,000 

bbls/day (or ~100 bbls/hr to 250 bbls/hr). There is a significant drop off in the flow 

rate at or near the 10 day mark to ~ 1000 bbl/day (or ~ 40 bbl/hr), and another significant drop at the 30 day mark to ~100-150 bbl/day (or 4 to 6 bbl/hr). Beyond the 50-

day mark, the flow rates are between 5 to 100 bbl/day but mostly ~ 10 bbl/day (or 0.4 

bbl/hr). 

Flowback, % of frac feed

5%

10%

0%

15%

20%

25%

30%

35%

40%

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14

Flowback, % of frac feed

5%

10%

0%

15%

20%

25%

30%

35%

40%

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14
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Figure 6 Flow rates vs. Flowback time for a few wells in the Marcellus shale (Gaudlip4).

Blue points refer to ―Flowback‖ and the red points refer to ―Produced‖.

Horn10 has reported flowback attributes for a Woodford shale site. Their flow rate data is replotted in Figure 7. We again observe that the flow rate was ~ 150 bbl/hr for the first 3 days 

and then decreased with time. At the 10-day mark, the flow rate was ~ 50 bbl/hr. In this 

case, at the 14-day mark, only ~34% of the ~95,000 barrels used for hydrofracturing had 

been recovered.

Figure 7. Flowback rate vs. time for a Woodford shale (re-plotted from the data shown in Horn10).

Flowback time, days

Flowback and Produced Water 

Flow Rates, bbl/day

Flowback time, days

Flowback and Produced Water 

Flow Rates, bbl/day

Woodford Shale Site flowback

-

50

100

150

200

0 2 4 6 8 10 12 14 16

Flowback time, days

Flowback rates, 

bbl/hr
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In Figure 8, typical flowrates for the Woodford that were shared by a customer are shown. 

We see that the flowrate profiles for two of the wells are similar as in Figure 7 while the 

flowrate decreases rapidly for one of the wells. 

Flowback Composition

For the Marcellus shale, the flowback compositions for a few sites have been reported by 

Gaudlip4. The composition of a flowback sample from a Marcellus shale site is reproduced in 

Figure 9.

Figure 9. Composition of a flowback sample from a Marcellus shale site (reproduced from Gaudlip4).

Figure 8. Flowrate profiles for frac flowback from three Woodford shales.
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Although the TDS of ~ 160K ppm of this particular sample is too high for any reverse-osmosis 

membrane based recovery processes, there are some interesting observations to be made, 

as described below. 

 The chlorides concentration at ~97K ppm make up ~60.6wt% of the TDS. Interestingly, this value is remarkably close to the value of 60.8 wt% that we would obtain if we 

assume that the TDS were entirely due to NaCl (based on the ratio of molecular 

weights, MCl/MNaCl =35.5/58.5 = 0.608). However, note that the Na content in Figure 4 

corresponds to only 23.2wt% in the flowback sample vs. 39.2wt% in pure NaCl. 

 The concentration of the ―hardness‖ ions (divalents – Ca, Mg, Ba, Sr) correspond to 

~56K ppm when reported on a CaCO3 basis. The ratio of Hardness (CaCO3 basis)/TDS = 56K/160K ~ 0.35. This value is in close agreement with several other data 

that we have examined for the Marcellus shale. This ratio varies amongst different 

shales with values ranging from 0.2 to 0.35 depending on downhole soil conditions 

and the composition of the water used for hydrofracturing.

 The source of potassium is perhaps from KCl added to the fracturing fluid during hydrofracturing. So, it may be desirable to retain it in the product water for frac re-use.

 The Sulfates concentration is low at ~ 8 ppm. This is not surprising since the Ba and 

Sr concentrations are so high at 203 and 2243 ppm, respectively. This also implies 

that most of the divalents and trivalent ions are present in the form of chlorides that 

have higher solubilities in water in relation to NaCl.

 The Fe content of 143 ppm may be too high for re-use, especially since it is in the Fe2+

state, which may potentially get oxidized and form undesired precipitates that could 

cause scaling.

Gaudlip4 has also reported on the variation of chloride concentration in the flowback as a 

function of flowback time, as reproduced in Figure 10. From our general observation noted 

earlier of the relationship between Cl and TDS in flowback waters, we may obtain a rough 

estimate of the TDS by dividing the Cl values by 0.61. From Figure 10, we note that in the 

Marcellus shale, the Cl values rise quickly, as follows: 

Cl, ppm Estimated TDS, ppm

Day 5: 20K to 70K 33K to 115K 

Day 10 : 40K to 90K 66K to 148K 

Day 15: 55K to 110K 90K to 180K 

From the above data, we observe that the ―low-TDS‖ water recovery processes (<45,000 ppm 

TDS in flowback) may have limited applications in the Marcellus shale play. However, we observe from composition data obtained from elsewhere in the Marcellus shale play from con-
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fidential sources, that 10-20% of the flowback may be amenable at certain locations with 

appropriate water management to isolate the first < 3~5 days of flowback water.

Figure 10. Variation of flowback composition with time for a Marcellus shale site (reproduced from 

Gaudlip)

For a Haynesville shale site, Kaufman et al15 have described the flowback composition. The 

data for the sulfates and Ba/Sr compositions plotted as a function of the cumulative flowback volume are reproduced in Figure 11. We observe a sharp transition at ~ 11,000 bbls 

when the Ba/Sr concentrations increase to cause a precipitous drop in Sulfate concentrations. 

Figure 11. Variation of Sulfates and Ba/Sr concentrations as a function of flowback volume for a 

Haynesville shale

Sulfates and Barium/Strontium

Sulfates Barium/Strontium
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For the Woodford shale, Total Dissolved Solids (TDS) concentration profiles for a few wells are 

shown in Figure 12. We observe that the concentrations increase from nearly zero initially to 

between 15,000 ppm to 35,000 ppm over the next 15 days. 

3.2.6 Summary of the flowback attributes

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 shale play, the geological formation, and the chemicals introduced 

during the drilling and fracturing operations. Flowback volume and water properties vary 

throughout the lifetime of the well.

3.2.7 Flowback volumes amenable to ―Low-TDS‖ membrane-recovery

Flowback waters with composition in the <45,000 ppm range are highly amenable for economic recovery using RO-based membrane recovery systems.

The initial flowback typically has low enough salinity to qualify for recovery via the methods 

that were investigated in this project. However, as noted earlier, the TDS levels increase with 

flowback volume, and the rate of increase depends on the shale formation, the TDS of the

water used for hydrofracturing, etc. Based on our survey of available literature information, 

the salinity ranges of the flowback waters from the various shales are shown in Table 2. The 

average values represent a combined mean for flowback from a well while the maximum 

could be an instantaneous value. Note that the actual values will vary widely from the numbers given here depending on the well location, chemistry, etc.

Figure 12. Total Dissolved Solids (TDS) concentration profiles for 

flowback waters from a few Woodford shale wells
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Table 2. Salinity of the flowback waters from various shales expressed in terms of Total Dissolved 

Solids (TDS).

The extent of applicability of our low-TDS recovery approach for the various shales would be 

~100% of the flowback from the Fayetteville and Woodford shales. In the Barnett shale, by 

selectively directing the flowback from the first 5 days, ~30-40% of the flowback may be 

amenable to the Low-TDS recovery (note, however, that this recovery process may not be 

considered at all since deep well disposal is easily available and so cheap - unless water 

availability may be an issue due to drought conditions). In the Marcellus shale, overall, only a 

small fraction (<10%) of the flowback may be amenable to Low-TDS recovery; however, 10-

20% of the flowback may be amenable at certain locations with appropriate water management to isolate the first 3~5 days of flowback water. In the Haynesville shale, due to the 

high TDS salinity and the availability of saline water disposal sites in East Texas, there is limited scope for membrane-based frac flowback recovery. 

3.2.8 Flow volumes & flow rates

The amount of frac fluid used depends on the type of well, the geographical location and operator bias/experience:

Well type Range Mean

Vertical 11,000 – 90,000 bbls 40,000 bbls

Horizontal 70,000 – 190,000 bbls 100,000 bbls

Flow rates during flowback typically show the following characteristics as a function of flowback time:

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%

%flowback after 90 days: 25~40%, but could be higher in certain wells. 

However, it is important to note that there is considerable variation in the flow rate profiles 

during flowback, and the water recovery cleanup system needs to be robust to these flow 

fluctuations.

Shale Average TDS, ppm Maximum TDS, ppm

Fayetteville 13K 20K

Woodford 30K 40K

Barnett 80K >150K

Marcellus 120K >280K

Haynesville 110K >200K
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3.2.9 Frac site visit

We visited a frac site in the Barnett shale in Fort Worth, TX area to get a first-hand understanding of the flowback operations and the water-handling logistics. Due to safety concerns, we could not visit this site during the hydrofracturing process but our visit happened 

immediately after the ―frac-job‖ and while the well services crew was managing the flowback. We also visited a saline water deep well injection site in the Cleburn, TX area. In Figure 

13, the photograph shows a saline water disposal (SWD) well co-located with three hydrofractured wells producing gas. At this site, the saline water was being disposed into the Ellenburger formation that was below the shale-gas formation layer. One of the remarkable 

impressions of these site visits was the general cleanliness of the operational sites once the 

flows were established. 

At this site, the saline water was being injected into the Ellenburger formation that is below the 

shale-gas formation layer.

3.2.10 Flowback samples

It had been challenging to obtain water samples from frac flowback, as frac operators prefer 

to keep the information proprietary and confidential. After several months of trying, we were 

fortunate to obtain flowback samples from two wells in the Woodford shale in Oklahoma. 

The well was hydrofractured in mid-March, 2010. For client confidentiality reasons, the customer and sites will not be identified in this report. The sample collections from the sites were 

as follows:

 Site-1: We coordinated with the customer to collect water samples during the initial 

flowback. 

o Daily 1-liter samples were collected from Day-1 through Day-14

o One 55-gal drum from Day-1. This is referred to as ―Site-1 Day-1‖ sample.

o One 55-gal drum containing a composite of several daily samples. This is referred to as ―Site-1 Composite‖ sample. 

Figure 13. Photograph shows a saline water disposal (SWD) well co-located with three hydrofractured wells 

producing gas. 
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 Site-2: One 55-gal drum of sample was collected on the Day-26 after flowback had 

started. This is referred to as ―Site-2 Day-26‖ sample.

In the sections below, the variation of frac flowback flow rate and the concentrations of the 

various components/contaminations in the above mentioned flowback waters are discussed.

3.2.10.1 Flowback rate profile

The profile for the flowback rate for Days 1-14 at Site-1 is shown in Figure 14. We observe 

the highly varying nature of the flowrate profile on an hourly basis. Over the first 11 days, the 

flowrate is approximately constant at about 120 +/- 15 bbl/hr. Beyond Day-12, the flowrate 

appears to decrease with time. Interestingly, the flowrate profile at this Site-1 is different 

from the profiles shown in Figures 7 and 8, also for wells in the Woodford shale, wherein the 

flow rate drops steeply over the first 10 days of flowback from ~150 bbl/hr initially to ~ 50 

bbl/hr. This illustrates one of the key issues with frac flowback water treatment, especially for 

an on-site mobile rig that will have to be robust to such varying flow profiles not only at the 

same frac sites but also that anticipated across different frac sites, although in the same

shale geology. 

3.2.10.2 Flowback Temperature:

In Figure 14, the temperature profile for the flowback water from Site-1 is also plotted. We 

note that the temperature is about 150°F. The flowback water temperature varies across 

frac sites and with time. Water from deeper wells tends to have higher temperatures. Also, 

the temperature is higher initially when the flowback rates are highest and gradually decreases with time. This relationship is apparent in the flow rate and temperature profiles in 

Figure 14. This aspect of the flowback has implications on the choice of process technologies 

and design of on-site mobile rigs to make them robust to varying temperatures; alternatively, 

-

20

40

60

80

100

120

140

160

180

200

- 2 4 6 8 10 12 14 16

Flowback time, days Flowback rate, bbl/hr

0

20

40

60

80

100

120

140

160

180

200 Water temperature, °F

Flowback rate, bbl/hr Water Temp

8 per. Mov. Avg. (Flowback rate, bbl/hr)

Figure 14. Profiles of the flowback water rate and water temperature are plotted vs. flowback time for the Site-1 in Woodford shale.
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we may need to install adequate heat exchange equipment if the chosen treatment processes have limited temperature operating ranges.

3.2.10.3 Flowback Water Composition

The water samples were analyzed at the GE Water Analysis Lab, Woodlands, TX, employing 

standard techniques used routinely for analysis of frac flowback and produced waters. The 

compositional data for the various components of interest are shown below in Figures 15-23.

Total Dissolved Solids (TDS)

The TDS values for Woodford Sites 1 and 2 are plotted in Figure 15. The TDS profile for Site-1

Days 1-14 was surprising. The Day-1 sample had ~ 38,000 ppm TDS and the value climbed 

up to ~ 85,000 ppm TDS on Day-14. This is in contrast to all the other data we had seen from 

customers in the Woodford shale, wherein the general trend showed that the TDS after Day14 was between 10,000 and 38,000 ppm, as seen in Figure 12. Interestingly, the Day-26 sample from Site-2 had ~35,000 ppm TDS, which is in agreement with the general trend. Horn10

has reported a value of ~13,800 ppm TDS for a Woodford shale site flowback water. It is not 

known why the Site-1 flowback shows such elevated levels of TDS. 

Total Suspended Solids (TSS)

These are fine particulates of inorganic, metallic or organic materials, typically < 5 μm in size. 

They can also be colloidal in nature. The TSS measurement is conducted by passing the water sample through a 1.0 micron filter and weighing the residue material after drying. Turbidity, measured and reported in NTU units, refers to the transmission (or lack of) of light 

Figure 15. Concentration profiles for Total Dissolved Solids (TDS) for the two Woodford frac sites.
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through a water samples. Turbidity may be influenced by the suspended solids and also color of the sample. 

In Figure 16, the TSS and Turbidity profiles for the Woodford Sites 1 and 2 are plotted. We 

note that the TSS generally decreases as a function of flowback time for Site-1 flowback from 

as high as ~825 mg/l on Day-1 to below detection. Interestingly, the Site-2 Day-26 sample 

also had low TSS values. Many of the produced waters (late flowback) obtained from other 

shales also typically show very low TSS values.

The Turbidity values, however, show a changing profile as a function of flowback time for the 

Site-1 flowback. This observed change in Turbidity (NTU) measurements may be influenced 

by the sample color. The Day-26 sample from Site-2 shows a value of ~ 300 NTU, which is in 

the range of the values measured for the Site-1 Days 1-14 flowback.

Figure 16. Concentration profiles for Total Suspended Solids (TSS) and Turbidity for the two Woodford frac sites.

Organics:

The organic content of the flowback waters was measured by two techniques, namely via 

―hexane extraction‖ and by Total Organic Carbon (TOC). The ―Hexane Extractables‖ method 

gives a measure of the components that are hexane soluble and is a good indicator of the 

free Oil & Grease content of the frac flowback water. The TOC measures the amount of combustible organic carbon present in the frac flowback water and is an indicator of dissolved 

and undissolved organics, including non-volatile and volatile compounds. Chemical Oxygen 

Demand (COD) is typically also mentioned in such water analyses; however, the presence of 

high amounts of chlorides interferes with this test and gives inaccurate results, and hence is 

not reported here. 
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The profiles for the Hexane Extractables and TOC for the flowback waters for the Woodford 

Sites 1 & 2 are plotted in Figure 17. For the Site-1 flowback over Days 1-14, we observe high 

initial values for Hexane Extractables followed by a sharp decrease over the next few days. 

The values are below detection beyond Day-10 for Site-1 which also corresponds to negligible value for the Day-26 sample from Site-2. The TOC profile for the Site-1 Days 1-14 samples also shows a high initial value of ~ 180 mg/l for Days 1 & 2 followed by a sharp decrease 

over Days 3 & 4, but then increases to a value of ~ 30 mg/l over the next few days. The value 

for the Day-26 sample from Site-2 is ~ 18 mg/l. It is likely that the Site-2 flowback may have 

gone through a similarly varying profile before settling to a steady value. 

Figure 17. Concentration profiles for Hexane Extractables and Total Organic Carbon for the two 

Woodford frac sites.

It is likely that the nature of the organic compounds changes over the flowback period. The 

data for the initial flowback may be reflective of the compressor oils, diesels and frac chemicals present immediately after a frac operation, while the data for the subsequent flowback 

may be reflective of more natively present organics (―connate‖) or organic species that are 

more water soluble. 

Hardness: 

Potential scale-forming ions, such as divalent and trivalent cations, such as Ca, Mg, Al, Ba, Fe, 

Mn, and Sr, and divalent anions, such as sulfates and carbonates, need to be measured & 

monitored. 

The Total Hardness estimated from the concentrations of the individual potential scaleforming ions and reported in terms of ppm CaCO3 is shown in Figure 18. We observe that 

for the Site-1 Days 1-14 flowback, the values climb from an initial ~ 4,000 mg/l CaCO3 to ~ 
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14,000 mg/l CaCO3 by Day-14. By contrast, the Day-26 sample from Site-2 shows a significantly lower value of ~ 2,000 mg/l CaCO3.

In Figure 19, the Total Hardness is plotted as a function of the TDS in the water samples for 

the two Woodford frac sites. Interestingly, we observe the Total Hardness showing an almost 

linear relationship to the TDS. Horn10 has reported a value of 1163 ppm Total Hardness for a 

Woodford shale site flowback water containing~13,800 ppm TDS.

Figure 18. Concentration profiles for Total Hardness and Alkalinity for the two Woodford frac sites.

Figure 19. Plot of Total Hardness (mg/l CaCO3) vs. Total Dissolved Solids (TDS) for the various frac 

flowback water samples collected from the two Woodford frac sites.
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In Figure 20, the contributions of Ca and Mg to the Total Hardness are further elucidated for 

the flowback waters from the Woodford shale sites. We observe that for the Site-1 Days 1-14 

flowback, nearly 98% of the hardness of the initial flowback is due to Ca & Mg, while this value decreases to ~ 95% for later days. For the Day-26 sample from the Site-2 flowback, Ca & 

Mg contribute to only 91% of the Total Hardness.

Interestingly, when the Chloride levels are plotted against the TDS, as shown below, we 

observe a linear correlation with slope of 

0.618, which is remarkably close to the 

value of the value of 0.608 that we 

would obtain if we assume that the TDS 

were entirely due to NaCl (based on the 

ratio of molecular weights, MCl/MNaCl 

=35.5/58.5 = 0.608). However, note that

the flowback samples contain varying 

amounts of the other cationic species 

besides Na. Such an observation was 

made earlier with regard to Figure 9 for 

data from the Marcellus shale. 

Figure 20. Profiles for the contributions of Calcium, Magnesium and Others (Fe, Sr, Ba) in 

terms of mg/l CaCO3 for the two Woodford frac sites.
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Barium, Strontium and Sulfates: 

Ba as a contaminant is a concern as in many plays the Ba levels are too high for frac reuse 

due to scaling concerns. Since BaSO4 has very low solubility, when Ba++ concentration is 

high, SO4— concentration is low, and vice-versa. This is apparent in the profiles for Ba, Sr and 

SO4 for the two Woodford frac sites seen in Figure 21. We also observe that the Ba concentrations increase from ~3 ppm initially to ~ 68 ppm on Day-14 for the Site-1 Days 1-14 flowback while the Site-2 Day-26 flowback sample has only ~ 30 mg/l. Horn10 has reported a value of ~38 mg/l Ba for a Woodford shale site flowback water. By contrast, some areas in the 

Marcellus shale may have even as high as 6,000 mg/l Ba.

Figure 21. Concentration profiles for Barium, Strontium and Sulfate for the two Woodford frac 

sites.

The Strontium concentration increases from ~ 70 ppm initially to ~ 480 ppm on Day-14 for 

the Site-1 Days 1-14 flowback while the Site-2 Day-26 flowback sample has only ~ 174 mg/l. 

The Sulfate concentrations decrease from ~ 100 mg/l initially to below detection beyond Day10 for the Site-1 Days 1-14 flowback, while the Site-2 Day-26 flowback sample has negligible 

concentration. 

Iron, Manganese and Boron:

Fe

2+ is a concern as it may oxidize to form Fe3+, which may readily form precipitates with various anions. Similarly, Mn may oxidize to form precipitates. The concentration profiles for Fe, 

Mn and B are plotted in Figure 22 for the two Woodford frac sites. 
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We observe that the Fe concentration for the Site-1 Days 1-14 flowback is initially ~30 mg/l 

but decreases to ~ 10 mg/l over the next few days before rising to ~40 mg/l by Day-14. The 

Site-2 Day-26 flowback water contains ~ 72 mg/l Fe. This is important since the product 

specifications for frac re-use water require <10 mg/l Fe, as discussed later.

We observe that the Manganese concentration for the Site-1 Days 1-14 flowback is ~ 1 mg/l 

similar to the Site-2 Day-26 flowback.

We observe that the Boron concentration for the Site-2 Days 1-14 flowback is initially ~10 

mg/l and increases to ~18 mg/l by Day-14, while the Site-1 Day-26 flowback water contains 

~ 28 mg/l. Boron removal may be a concern if the product water is surface discharged but 

may not be an issue for frac re-use in slickwater hydrofracturing (however, B levels are tightly 

controlled in gel-based hydrofracturing).

Figure 22. Concentration profiles for Iron, Manganese and Boron for the two Woodford frac sites.

Silica:

Silica may be present in the flowback water either as colloidal silica or reactive silica; the latter is of concern as a potential foulant for desalination membranes. In Figure 23, the concentration profiles for both of these species are plotted as a function of flowback time for the two 

Woodford frac sites. We observe that there is some variation in both measurements of silica 

for the Site-1 Days 1-14 flowback with the values between 20 and 70 mg/l: the silica concentration for the Site-1 Days 1-14 flowback is initially ~60 mg/l but decreases to ~ 20 mg/l over 

the next few days before rising to ~70 mg/l total silica and ~55 mg/l reactive silica by Day-14. 

The Site-2 Day-26 flowback water contains ~ 120 mg/l total silica and ~60 mg/l reactive sili-
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ca. Removal of colloidal silica may occur during removal of suspended solids but removal of 

reactive silica is important to prevent RO/NF membrane fouling.

Figure 23. Concentration profiles for Total and Reactive Silica for the two Woodford frac sites.

NORM: 

Normally Occuring Radioactive Material (NORM) levels were not measured for these samples. 

Examination of some of the low-TDS waters from the Woodford shale reveal NORM values in 

the range from <20 to 500 pCi/L. These are very low compared to values in the Marcellus 

shale (reported at ~ 10,000 pCi/L). The treatment of NORM containing waters is being specifically addressed by GE Global Research under contract with Research Partnership to Secure 

Energy for America (RPSEA) (RPSEA 08122-36, principal investigator, Dr. James Silva). The results from that project, when available, will be incorporated into this project.

Composition analysis for the drum samples.

The compositions of the three 55-gal drums obtained from the Woodford shale sites are 

listed in Table 3. Photographs of vials containing these samples are shown in Figure 24.

The 33,800 ppm TDS of the Site-2 Day-26 sample was in the desired range for the evaluation 

of RO-type membrane processes for desalination and was used for membrane fouling studies in Task 4 and 5. Although the TDS values of the water samples obtained from Site-1 were

too high for the consideration of RO-type membrane processes for desalination, the samples 

were useful for the bench-mark evaluation of pretreatment processes for the removal of other undesired components in Task 4.
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Table 3. Compositions of the three 55-gal drums obtained from the Woodford shale that were 

used for bench-mark testing in Tasks 4 and 5.

2 /

GE Title or job number /

4/25/2011

Frac Flowback Water Sampling

Woodford shale Site1 Days 1-14

Woodford shale 

Site2 Day 26

Thanks to:

• Tom Hook - Woodford samples

• Preston Nelms - Fayetteville sample 

• Mark Wilson & Todd Langford

typical “bottom” 

of barrel 

Figure 24. Photographs of vials containing frac flowback samples from Woodford shale Site-1 

Days1-14 and Site-2 Day-26.

Components Site-2 

Day 1

Site-2 

"Composite"

Site-1 

Day 26

Specific Conductance, at 25°C, μmhos 51,100 71,125 54,200

Alkalinity, "M" as CaCO3, ppm 641 381 495

Sulfate, as SO4, ppm 134 104 35

Chloride, as Cl, ppm 23,900 21,000

Hardness, Total, as CaCO3, ppm 5,170 5,838 2,310

Calcium Hardness, as CaCO3, ppm 3,910 4,260 1,240

Magnesium Hardness, as CaCO3, ppm 1,180 1,348 855

 Barium, Total, as Ba, ppm 3 30 33

 Strontium, Total, as Sr, ppm 70 186 174

 Iron, Total, as Fe, ppm 24 22 73

 Sodium, as Na, ppm 14,100 14,600 19,100

 Potassium, as K, ppm 301 436 340

 Manganese, Total, as Mn, ppm 0.7 1.3 1.3

 Phosphate,Total, as PO4, ppm 12 12

 Silica, Total, as SiO2, ppm 67 47 120

 Silica, Reactive, as SiO2, ppm 63 44 59

 Solids, Total Suspended mg/l 841 277 n/a

 Solids, Total Dissolved, mg/l 39,100 59,475 33,800

 Boron, as B, ppm 10 13 28

Carbon, Total Organic, as C, ppm 187 42 17

Turbidity, NTU 367 143 297

Hexane Extractable Material, mg/l 149 14
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3.2.11 Specifications for the frac flowback water recovery process

3.2.11.1 Conventional Frac Flowback process

The frac flowback water handling process, although quite complex in terms of the safety and 

operational logistics, is shown simplified for our purposes in Figure 25. The flowback water is 

directed to a separator to separate the water from the gas and the solid proppants. The 

flowback water is stored in interim storage tanks. The water is trucked to water disposal 

sites. 

Figure 25. Simplified frac flowback water handling and disposal operation at a shale gas well site.

3.2.11.2 Conventional water disposal

Flowback water may be disposed of by various means including:

 Deep well injection: Disposal in Class II saline water injection sites has been the most 

common and sometimes the only means of disposal of the high-TDS flowback and 

produced waters. This has been especially true in the Barnett shale where such disposal sites are available locally and the cost of disposal is relatively cheap at $1-

$3/bbl. However, such deep well injection sites are few in the Marcellus shale (West 

Virginia, Pennsylvania, New York), and hence there is a need to transport the flowback waters to sites in Ohio and Indiana. The costs of such long distance hauling by 

trucks are in the range of $4- $19/bbl. An independent operator in the PA area indicated that his disposal costs were ~$8/bbl. In the Fayetteville shale (Arkansas) it can 

cost upwards of $6 per barrel to transport and dispose of water in an independently 

owned disposal well3. For the Woodford shale (Oklahoma), the trucking costs are estimated at $3.71/bbl and disposal between $1-2/bbl

10

.

 Surface water discharge: Until recently, this mode of disposal was used in the Marcellus shale in the PA area. PA DEP 25 regulations enacted in August 2010 limit surface discharge from Oil & Gas operations to less than 500 ppm TDS (among other 

specific constituents such as Chlorides, Sulfates, Barium and Strontium).

 Land farm use: This was used until recently in the Fayetteville shale in Arkansas, but 

there are restrictions to such use3. Waters cannot be land applied when the ground 

is saturated, frozen, or if precipitation is imminent. In order for water to be applied to 

the surface under land application permits, it must have a chloride concentration of 

Conventional Flowback Water Disposal Process

Interim 

Flowback 

Water 

Storage

Saline Water 

Disposal

120 bbl/truck

Ctransport : $2~$20/bbl

Flowback

water

Gas for sales

Proppant

Well head

For deep well injection: 

CSWD : $1 ~ $3/bbl

CDisposal = CTransport + CSWD ($/bbl water)
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less than 5,000 parts per million (ppm) and comply with a Sodium Adsorption Ration 

(SAR) specifications. If chloride content is less than 1,500 ppm, water can also be utilized on roads for dust suppression. If chloride concentrations exceed 5,000 ppm, disposal in approved disposal wells is required. 

3.2.11.3 Frac Flowback Recovery Process

A conceptual process for recovering all or part of the flowback water for re-use in hydrofracturing operations is shown in Figure 26. The flowback water recovery process (FWRP) is preferably located physically close to the well operations to minimize water hauling costs. It includes a mobile unit equipped with the necessary treatment operations to provide a ―product‖ water that meets specifications for re-use in hydrofracturing. Only a portion of the flowback water may be recovered as product, while the rest may have to be disposed of either in 

conventional saline water disposal Class II wells or via further recovery by methods suitable 

for desalination of high-TDS waters (> 70,000ppm), such as thermal processes.

Figure 26. Conceptual Flowback Water Recovery Process (FWRP) for re-use in hydrofracturing.

The overall cost will depend on the extent of water recovery, x, in the FWRP.

3.2.12 Technical specifications for recovery for frac re-use

1. Product composition:

The contaminants of interest in the frac flowback water for mitigation and their impact on 

water re-use for hydrofracturing are shown in Figure 27.
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Figure 27. Key contaminants in frac flowback water and their impact on re-use in hydrofracturing.

Opinions vary widely on the water quality that may be used for hydrofracturing. For instance, 

most of the operators currently insist on using very low-TDS source water to avoid scaling 

issues in the downhole piping. Some well operators, such as Range Resources, have reported 

success in using up to 26,000 ppm Chlorides in the Marcellus shale16. In fact, Range Resources and Chesapeake reported at the 2010 GWPC Conference, Pittsburgh, PA that they 

presently re-use ~100% of early flowback water in the Marcellus shale by blending with fresh 

water (TDS<500 ppm) in subsequent hydrofracturing operations. Some experts feel that water salinity equivalent to seawater, namely ~ 35,000 ppm TDS may be usable for hydrofracturing5

. Some operators are reportedly even considering the re-use of waters with salinity as 

high as 120,000 ppm TDS with low hardness and scale-causing contaminants17, but we consider these to be highly speculative at the present moment as these may be applicable to 

specific situations where blending with a majority of very low-TDS source water may be anticipated before frac use. 

To develop specifications for frac re-use water, we evaluated the limited information available in literature and spoke to frac operators. The data provided by Range Resources4 gives 

one benchmark for re-use specifications. This is reproduced in Figure 28 and provides a 

good understanding of a practical application. Apparently, the frac flowback waters from a 

Marcellus shale well site were blended with fresh water to create a frac fluid with the reported characteristics, which was successfully used for hydrofracturing at another site.
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Figure 28. Summary of chemical characteristics of the waters used in conventional and blended 

Marcellus waters used for hydrofracturing by the Range Resources Company4.

A specification for re-use frac water apparently developed with data supplied by Halliburton 

and XTO Energy are provided in Table 4.

Table 4. The following specifications for re-use frac water in the Marcellus shale were apparently 

developed18 with data supplied by Halliburton and XTO Energy

Parameter Range

maximum scale formers* 2,500 mg/l as CaCO3

maximum dissolved solids 50,000 mg/l

maximum iron 3.5 mg/l

maximum calcium 250 mg/l

pH range 6.5 to 7.5

* scale formers are generally considered to be aluminum, barium, calcium, iron, manganese, and strontium

Moreover, the methods used for hydrofracturing are being continuously updated as the industry is trying to maximize gas recovery while minimizing energy and especially, fresh water 

usage. For example, current research on new slicking agents (friction reducers) may allow the 

use of higher salinity in the feed water compared to present operations. Regulations are being considered by various state and federal agencies on the disclosure of water chemistry 

used for hydrofracturing, discharge of flowback water, and the re-use of flowback water for 

hydrofracturing. Until the frac industry has honed in on their requirements, there will be uncertainty on the specifications for the treated water and discharge water. This affects the 

determination of how much of the flowback water would be treatable, the choices of technology options applicable and the overall system cost. The conclusion from our survey was 

that the specifications for acceptable re-use are subject to change in the short-term.

Based on the feedback from hydrofracturing operators, it was realized that the team needed 

to update the product water scope from the one product with 20,000 ppm TDS originally proposed to potentially four alternative products with varying levels of purification:
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1. Product-1: Clarified only (removal of suspended matter, free oil & grease, Fe, and microbiological contaminants), 

2. Product-2: Softened and Clarified (removal of hardness ions, namely Ba, Sr, Ca, Mg 

besides the purity specs for Product-1), 

3. Product-3: Partially desalinated to < 20,000 ppm TDS (besides the purity specs for 

Product-2), and 

4. Product-4: Substantially desalinated to < 500ppm TDS (besides the purity specs for 

Product-2). 

These product options and the associated target contaminants for removal are shown in 

Figure 29.

Frac Flowback Recovery: Product Options

Suspended solids

Free Oil & Grease

Bacteria

Colloidal organics*

Dissolved Organics*

Fe, Mn

Clarified only 

(for frac r e-use)

Ba, Sr, 

Ca, Mg

Sulfates

<500 ppmTDS

for surface 

discharge

Flowback 

water

To Disposal

Concentrate

Solid waste 

for disposal

Softened (for 

frac r e-use)

Na, C l, 

K, Ca, Mg, 

SO4, 

organics

Concentrate Desalinated 

(for frac r e-use)

Product options

Product-1

Product-2

Product-3

Product-4

Desal

Clarify

Soften

Figure 29. . Product Options for frac flowback water recovery. The target contaminants are listed 

for each process step in the respective boxes. The target contaminants to be removed in each process step are indicated inside the boxes.

The specifications for the products under consideration are shown in Figure 30. It should be 

noted that as the shale gas industry is continually evolving in terms of the water quality used 

for hydrofracturing, the specifications are based on currently best available information from 

operators and published literature. The first three product waters would be suitable for reuse in hydrofracturing while Product-4 would also be suitable for surface discharge. It should 

be noted that the product quality requirements increase as we consider Product-1 through 

Product-4, both in terms of the number of target contaminants as well as the extent of their 

removal. For example, dissolved organic contaminants at levels < 50 ppm may not be as 

much of an issue with Product-1 and Product-2, namely Clarified-only and Softened-only, 

respectively; however, these contaminants at levels >10 ppm may be foulants for the desalination membranes that would be used to produce Product-3 and Product-4.
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Parameter Units

Conventional 

"fresh" source 

water before 

additive 

blending

Conventional 

frac fluid 

after additive 

blending

"Clarified 

product" for reuse

"Softened 

product" for reuse

"Desal 

water" 

product for 

frac re-use

"Desal water" 

product for 

agricultural 

discharge

Total Dissolved Solids mg/L <500 <1000 NR NR <20,000 <500

Total alkalinity mg/L ~ 50 ~50 <600 <600 <600 ~ 50

Hardness as CaCO3 mg/L <150 <150 NR <2000 <2000 See SAR

Total suspended solids mg/L <2 ~ 10 <50 <50 <50 <50 <2 ~ 10

Turbidity NTU < 4 <250 <100 <100 <100 < 4

Chloride mg/L <50 <100 NR NR <12,500 <50

Iron mg/L < 4 <10 <10 <10 <10 < 4

Oil & soluble organics mg/L <10 <400 <50 <50 <50 <29

Sulfate mg/L <25 <25 <125 <25 <25 <25

Total Phosphorus mg/L ~0.1 0.1 ~ 5 NR NR NR < 5

Bacteria Count #/100mL <100 <100 <100 <100 <100 <100

pH 6.7 - 7.4 5.2 - 8.9 6.5 - 8.5 6.5 - 8.5 6.5 - 8.5 6.7 - 7.4

SAR NR NR NR <12

Temperature C NR NR NR ambient

* Best available specifications from few operators and published literature. Actual values may vary 

depending on shale formation, local regulations and operator preferences.

* * *

Requirements for the “product” waters

*

Note that due to addition of the various chemicals for friction reduction, etc. (see Appendix 

for details), there is a net increase in the TDS and other components in the frac fluid relative 

to the source water, as seen in Figure 30 for the compositions of the frac fluid before and after additives blending for a conventional ―fresh‖ water source. Also, the specifications for 

Product-3 appear to be roughly half of the Chlorides and TDS reported by Range Resources in 

Figure 28. We felt that it was prudent to take a conservative approach.

2. Extent of product recovery

The extent of recovery of the product water (fit for frac re-use), x, is defined as:

For Product-1 and Product-2 in Figure 29 that involve only processes such as filters, clarifiers, 

sorbents, and precipitation equipment, the water recovery is typically >90% or higher depending on the efficiency of the sludge handling methods employed. 

However, the extent of product permeate recovery in membrane desalination processes is 

limited by the feed water composition (including salts, hardness ions, silica, organics, etc.), the 

pressure limitations of the pumping equipment used and the membrane area available. As 

water permeates through the selective membrane inside the permeator module, the concentration of salts and other non-permeable components, such as silica, organics, etc., increase 

in the retentate. This results in the need for a greater pressure drop across the membrane 

for reasonable permeate production rates, and also increases the potential for precipitation 

of insoluble salts, such as CaCO3, CaSO4, BaSO4, SrSO4, etc. and fouling of the membrane by 

reactive silica and other contaminants. Typically, for economically viable sea water desalination, the upper limit on the concentration of the retentate in RO processes is about 70,000 

Figure 30. Specifications for the various Product Options described in Figure 29.

Volume flowback water

Volume recovered water

x 
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ppm – the actual value will depend on the concentrations of the other ions, silica and other 

components. 

In Figure 31, the extent of recovery, x, is plotted as a function of the flowback TDS concentration for different values of the permeate product TDS concentrations, namely 250 ppm, 

10,000 ppm and 20,000 ppm. The value of 250 ppm TDS corresponds to a very low-TDS 

product that is suitable for potable water or surface discharge (Product-4), and the value of 

20,000 ppm TDS corresponds to our proposed ―frac re-use‖ (Product-3) specifications shown 

in Figures 29 & 30. The condition for typical seawater desalination to produce potable water 

(<250 ppm TDS) is also shown in Figure 31.

26 /

GE Title or job number /

5/3/2011

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

- 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

TDS in Flowback, ppm

X, extent of flowback recovery, ppm

Series1

Series3

Series2

Product 

TDS, ppm 250

20,000

10,000

Seawater 

desalination

Flowback range 

applicable for 

“Low-TDS” 

recovery process

X, 

fractional 

flowback 

recovery

Figure 31. Plot of extent of product recovery, x as a function of the flowback water concentration 

and desired permeate product water concentrations when retentate concentration is limited to 

70,000 ppm TDS.

The applicable range of flowback water composition for ―Low-TDS‖ recovery processes is expected to be in the range of 15,000 to 45,000 ppm TDS depending on the shale play under 

consideration (see Table 2 for expected TDS ranges for different shales). For flowback water 

concentrations in the range of 30,000 to 45,000 ppm, the expected extents of recoveries 

are 50-80% for Product-3 (20,000 ppm TDS product) and 35-55% for Product-4 (500ppm 

TDS product).

3. Cost criteria:

Value Assessment of Flowback Water Recovery Process

The value of the Flowback Water Recovery Process (FWRP) would depend on the specifics of 

the shale site. The factors to consider are (a) the salinity and other contaminants in the flowback water that would limit the recovery (x), (b) the cost of conventional disposal options, (c) 
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any regulations (penalties) related to disposal of the flowback waters or use (benefits/incentives) of the product water for frac re-use, (d) the availability (or lack) of water for 

frac use, and (e) the cost and logistics of the infrastructure available to bring in a mobile unit 

at the frac flowback site.

The acceptable cost target of the recovery process would consequently be dependent on the 

specifics of the shale site under consideration. Of course, the preferred option is the ―cheapest‖ process that meets the technical specifications at the ―highest‖ recovery. 

When we consider the cost of a FWRP, we need to consider the following:

 Cost of recovery process to produce a product fit for frac re-use.

 Delivery of the product to the re-use site

 Value benefit of the fresh water avoided during the subsequent frac operation.

 Disposal of the unrecovered product via deep well saline water injection or some other recovery method (e.g. thermal recovery) including transportation.

These are represented below:

CFWRP = CRecovery + CConcentrate disposal ($/bbl feed) (1)

CRecovery = CTreatment + CProduct Delivery - (CFresh Water + CPenalties_Avoid) ($/bbl product) (2)

where the cost for the product recovery CRecovery includes the cost of the treatment processes 

and the cost for delivery of the product water to the re-use site. Additionally, credits could be 

taken for the value of the fresh water avoided during the next fracturing job, and any avoidance of penalties from existing or pending regulations. 

The volume and cost of water being withdrawn, and consequently not available for public 

consumption, is a significant public perception issue, especially during water-constrained 

situations (drought, etc.). But in most shale plays when water availability is not a concern, 

fresh water from river water and municipalities typically costs ~ $0.05/bbl plus delivery, 

which may result in a net cost of ~$0.22/bbl. This cost is small compared to typical saline 

water Class II disposal costs of $1-3/bbl. The value of the penalties avoided, CPenalties_Avoid is 

unknown at the moment. Hence, although inclusion of CFresh Water and CPenalties_Avoid offers a 

more economically attractive condition, a more conservative approach would be to ignore 

them, as in eqn. (3):

CRecovery  CTreatment + CProduct_Delivery ($/bbl product) (3)

The cost of delivery, CProduct_Delivery will again vary depending on the distance between the reuse site and flowback site, and the mode of product water transfer. The cheapest option will 

be to pump into a local pond dedicated to hold this product until re-use. The most expensive 
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option will be trucking over long distances. A reasonable estimate would be CProduct_Delivery < 

$0.1~0.5/bbl. 

For the Flowback Water Recovery Process to be economically attractive, the minimum requirement is:

CFWRP < CConventional Disposal

From our earlier discussions, we noted that the typical conventional disposal costs, including 

transportation, could vary depending on the individual shale plays and the availability of disposal sites. These values range from as low as $2-$4/bbl in Barnett to as high as $4-$19/bbl 

in Marcellus, while it is $6/bbl in Fayetteville3 and $3.71/bbl for transportation and ~$1-2/bbl 

for disposal in Woodford10. (Although, interestingly, during the Pennsylvania Chap 95 regulation analysis review, it was reported that even at costs anticipated for proper treatment and 

disposal at as high as ~$10/bbl, the annual costs would comprise a mere 0.4% of the estimated annual revenue19.). 

From these values and feedback from a few well operators, as well as paring down the contributions of product handling & delivery costs and rig operating labor, the treatment cost 

criterion for this project was set as:

CTreatment < $2/bbl feed

Where CTreatment = CSetup + CProcess

CSetup: Cost of mobile rig transportation and setup at the frac site.

CProcess: Cost associated with the capital and operating expenses related to the process steps 

including process equipment, chemicals, waste disposal and maintenance.

This is the treatment cost on-site and does not include the cost of product- and concentratedisposal. The labor costs associated with setting up the mobile rig are included in CSetup and 

thus in the CTreatment value. However, the rig operating labor for treating flowback water has 

not been included since these costs may be accounted differently by different producers as 

the rig may be run by operators handling multiple responsibilities at the frac site.

3.2.13 Summary of the verification of success criteria

The verification of success criteria are summarized in Figure 32.
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15 /

Harish R. Acharya, Global Research

Parameter Units

Conventional 

"fresh" source 

water before 

additive 

blending

Conventional 

frac fluid 

after additive 

blending

"Clarified 

product" for reuse

"Softened 

product" for reuse

"Desal 

water" 

product for 

frac re-use

"Desal water" 

product for 

agricultural 

discharge

Total Dissolved Solids mg/L <500 <1000 NR NR <20,000 <500

Total alkalinity mg/L ~ 50 ~50 <600 <600 <600 ~ 50

Hardness as CaCO3 mg/L <150 <150 NR <2000 <2000 See SAR

Total suspended solids mg/L <2 ~ 10 <50 <50 <50 <50 <2 ~ 10

Turbidity NTU < 4 <250 <100 <100 <100 < 4

Chloride mg/L <50 <100 NR NR <12,500 <50

Iron mg/L < 4 <10 <10 <10 <10 < 4

Oil & soluble organics mg/L <10 <400 <50 <50 <50 <29

Sulfate mg/L <25 <25 <125 <25 <25 <25

Total Phosphorus mg/L ~0.1 0.1 ~ 5 NR NR NR < 5

Bacteria Count #/100mL <100 <100 <100 <100 <100 <100

pH 6.7 - 7.4 5.2 - 8.9 6.5 - 8.5 6.5 - 8.5 6.5 - 8.5 6.7 - 7.4

SAR NR NR NR <12

Temperature C NR NR NR ambient

Verification of success criteria:

* Best available specifications from few 

operators and published literature. 

Actual values may vary depending on 

shale formation, local regulations and 

operator preferences.

* * *

 Requirements for the “product” waters Performance: 

 Cost of FWRP < Cost of Conventional Disposal

 Treatment cost <$2/bbl feed

 Mobile rig configuration feasibility

 Product recovery: >95% >90% >50% >40%

*

Figure 32. Verification of success criteria for the Low-TDS frac flowback recovery process
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3.3 Task 3: Define conceptual process alternatives for frac water recovery 

for re-use 

The specific objective was to:

 Evaluate possible frac water recovery flow schemes and obtain preliminary costs.

The key activities were to:

 Identify potential treatment technologies for the various contaminants identified in 

Task 2. 

 Generate preliminary process schemes with these various technology options and 

evaluate potential feasibility and risks to meet the technical product requirements, 

cost targets and mobility requirements.

We reviewed available technology options to remove the various contaminants of interest in 

frac flowback water. Additionally, we, at GEGR, worked closely with various groups within GE 

Water & Process Technologies (GEWPT) to leverage their knowledge in treating various industrial waste waters. Specifically, GEWPT Water Chemicals division offers a wide product portfolio of chemicals used for membrane-water pretreatment and corrosion prevention, GEWPT 

Membranes division offers a wide product portfolio on microfiltration, ultrafiltration, nanofiltration, reverse osmosis, and membrane bioreactors for treating various municipal and industrial waste waters. GE WPT Mobile Services offers the world's largest fleet of mobile water 

treatment systems, providing rapid response for a full range of reverse osmosis, filtration, 

demineralization, softening, and deoxygenation treatment on demand. 

3.3.1 Frac Flowback Water Recovery Process Options

A conceptual Frac Flowback Recovery Process (FWRP) scheme for treating the frac flowback 

water to provide product water fit for frac re-use is shown in Figure 33. 
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Frac Flowback Recovery Process

Clarify

Suspended solids

Free Oil & Grease

Bacteria

Colloidal organics*

Dissolved Organics*

Fe, Mn

Clarified only 

(for frac r e-use)

Soften

Ba, Sr, 

Ca, Mg

Sulfates

<500 ppmTDS

for surface 

discharge

Flowback 

water

To Disposal

Concentrate

Solid waste 

for disposal

Softened (for 

frac r e-use)

Desal

Concentrate

Y’s: System cost < Disposal cost for use application

Maximum recovery 

Robust operations for variable feed

“Green” process with minimal chemicals use

Desalinated 

(for frac r e-use)

Product options

Product-1

Product-2

Product-3

Product-4

Pretreatment 1

Pretreatment 2

Desal

Figure 33. Conceptual representation of a frac flowback recovery process to treat the frac flowback waters to provide the product options in Figure 30. The target contaminants to be removed 

in each process step are indicated inside the boxes.

The flowback water is first treated to remove the various contaminants shown in the Pretreatment-1 box in Figure 33. The key contaminants to be removed are suspended solids, 

free oil & grease, bacteria, colloidal organic and inorganic material. Dissolved ions are not 

removed. The outputs from this process are: (a) a clarified ―product‖ stream that will meet 

the Product-1 requirements specified in Figure 30, and (b) a small solids-rich waste stream 

produced from the precipitation and filtration steps for disposal. 

For Product-2, the output from Pretreatment-1 may be further treated to remove hardnesscausing ions, mainly divalent and trivalent ions, in the step shown as Pretreatment-2 in Figure 33. It is possible, as shown later, to combine the processes in the Pretreatment-1 and -2 

steps. The outputs from this process are: (a) a softened ―product‖ stream that will meet the 

Product-2 requirements specified in Figure 30, and (b) a solids-rich waste stream that needs 

to be disposed of, preferably as a non-hazardous waste disposed of in a land-fill, or a liquid 

waste stream that is concentrated in the divalent and trivalent ions that is disposed of in an 

underground saline water injection facility. The solids-rich waste stream would be generated when precipitation methods such as ―lime softening‖ are used, followed by settling and 

filtration. A liquid-rich waste stream would be generated when a nanofiltration membrane 

process that selectively rejects di- and tri-valent ions is employed. The extent of water recovery is definitely higher for the solids-precipitation method but it requires handling of solids. 
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To meet the Product-3 and Product-4 requirements, the output from Pretreatment 2 would 

require the use of desalination membranes that selectively exclude the permeation of monovalent ions, such as Na, K, and Cl besides any residual divalent and trivalent ions. The extent 

of salt removal is influenced by the choice of desalination membranes employed. The extent

of removal could be least when nanofiltration (NF) membranes that remove the divalents and 

some of the monovalents are employed and most when high-selectivity reverse osmosis (RO) 

membranes are employed. The NF membranes have the highest permeate flux and would 

require the lowest membrane area and lowest operating pressure (~100 psig range), while 

the high-selectivity RO membranes typically have the lowest flux and would require the largest membrane area and highest operating pressure (800-1200 psig), and thus the highest 

electrical power consumption (kW/m3 of permeate). Membranes with intermediate ranges of 

flux and selectivity may also be considered for an optimal flux/area/power requirement for 

the desired product TDS quality. 

The retentate or concentrate stream from the membrane desalination process would be sent 

to disposal in deep well injection wells, or as feed to thermal desalination systems that can 

recover more useful water for reuse and further concentrate the saline stream to reduce the

volumes for deep well injection. An ideal situation would be in a zero liquids discharge (ZLD) 

facility wherein all the water is recovered and the residue is a valuable by-product salt useful 

as an industrial raw material or as road-salt.

3.3.2 Key contaminants in frac flowback of concern for reuse

The contaminants in the frac flowback water were discussed in Section 3.2.10.3 and their impact on water reuse for hydrofracturing were illustrated in Figure 27. The salient aspects of 

these contaminants for evaluating process technology options for cleanup are described below:

 Particulates: These could be precipitated solids, sand and silt, carbonates, clays, 

proppant, corrosion products, and other solids derived from the producing formation 

and from well bore operations. Quantities can range from insignificant amounts to 

high enough to yield a solids slurry. In theory, these should be amenable to removal 

via filtration or other mechanical means.

 Suspended solids: These are finer particulates of inorganic, metallic or organic materials. They can also be colloidal in nature. Reported values are typically ~ 200 ppm 

but could be much higher depending on the particular operating conditions of the 

flowback. There could be significant variability in the values during the flowback.

 Free oil and grease (FOG): These could be from the oils and diesels from compressors 

and other drilling equipment or native from the producing formation. There is a lot of 

fluctuation in the reported values even in the same shale. There could be significant 

variability in the values during the flowback.
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 Dissolved Organics: These could be small amounts of low molecular weight hydrocarbons, polymers used as friction reducers (see Appendix), or other organics from 

the formation. Reported values range from 10 – 150 ppm.

 Volatile Organics: Some of the dissolved and undissolved organics could be considered as volatile under normal operating conditions and as such may present concerns with emissions or fire/explosion hazards if the concentrations are too high. 

Condensates present in the shale gas that contaminate the flowback water, especially benzene, toluene and xylenes, need to be explored as they are of public concern. 

Most literature values indicate <10 ppm for such compounds.

 Hardness: These include divalent ions, with the ions of most concern being Ca and 

Mg. The concentrations of these ions are high in certain shales, such as Marcellus 

while low in shales such as Woodford and Fayetteville. They could range from ~100 

ppm to 10,000 ppm depending on the shale and vary as a function of flowback time 

(typically increase almost linearly with TDS). 

 Barium: Ba as a contaminant is a concern as in many plays the Ba levels are very 

high. Since BaSO4 has very low solubility, when Ba++ concentration is high, SO4—

concentration is low, and vice-versa (see Figure 11 for the Haynesville shale data). 

Reported Ba values range from <100 ppm in Woodford to as high as 6,000 ppm in 

certain areas of Marcellus. Even in Marcellus, there is significant variation as one 

travels from WV via PA to NY.

 Strontium: Reported values range from <50 ppm in Woodford to >2,000 ppm in Marcellus.

 Iron: Reported values range from 20-200 ppm. Fe++ is a concern as it may oxidize 

and form precipitates with various anions. 

 Silica: Reported values range from 10 – 120 ppm. This could be colloidal silica or reactive silica; the latter is of concern as a potential foulant for desalination membranes.

 NORM: NORM originates in geological formations and can be brought to the surface 

with the flowback water. The NORM values for some of the low-TDS waters from the 

Woodford shale appear to range from <20 to 500 pCi/L. These low values do not 

pose any concerns for treated water or any waste residues produced during recovery 

of the saline waters considered in this project. 

3.3.3 Considerations for evaluating technology & process options

A review of available technology options to remove the various contaminants of interest in 

frac flowback water was conducted. Process flow schemes with these technology options 

were created. The technology options were rated for the following:

 Technical Performance: Will the technology option remove the contaminant to the 

desired specification? Can it be integrated with the other process technologies to 

yield a technically workable process solution?

 Cost Performance: Will the technology be cost-effective? Will the overall process 

cost incorporating this technology be cost-effective?
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 Mobility Performance: Does this technology have a low enough footprint that makes 

it amenable to incorporation into a mobile rig? Will the overall process using this 

technology be usable in a mobile rig?

The following rating scale was used:

 Green: The risks are low with this technology option for this contaminant. Also, overall process integration with this technology carries low risks

 Yellow: There are some low-med level risks with this technology option that would 

need to be retired either using pretreatment or post-treatment. For example, polyamide membranes typically used for desalination will get fouled at high concentrations of reactive silica or precipitating salts, such as CaCO3, CaSO4, etc. Therefore, 

there is need to pre-treat the feed to this membrane unit to remove the potential foulants or add anti-scaling agents.

 Red: The technology option has some substantial risks that need to be retired by either pretreatment or post-treatment.

The results of the analysis are shown in Figure 34. The conclusions from the analyses are discussed in the next section. 
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Figure 34. Technology options evaluated in the preliminary screening in Task 3 for removal of the various contaminants in frac flowback water. 

Technology Brief description TSS TDS 

(monvalent) Ca, Mg Silica Iron 2+ O&G dissolved organics Ba

Performance Risks small particles

Cost risk

Mobility

Performance Risks small particles

Cost risk

Mobility

Performance Risks dissolved Si

Cost risk

Mobility

Performance Risks dissolved Si via sulfate

Cost risk

Mobility

Performance Risks scale on electrode dissolved Si uncertain removal

Cost risk

Mobility

Performance Risks small particles

Cost risk

Mobility

Performance Risks

Cost risk

Mobility

Performance Risks high levels

Cost risk

Mobility

Performance Risks smaller droplets

Cost risk

Mobility

Performance Risks fast loading

Cost risk

Mobility

Performance Risks fouling risk Si specific resin

Cost risk

Mobility

Performance Risks small particles not for high conc

Cost risk

Mobility

Performance Risks foul at high conc

Cost risk

Mobility

Performance Risks

Cost risk

Mobility

Performance Risks kinetics; chemicals

Cost risk

Mobility

Performance Risks kinetics; chemicals foaming

Cost risk

Mobility

Performance Risks

Cost risk

Mobility

Performance Risks dosing; filter fouling

Cost risk

Mobility

Performance Risks small particles

Cost risk

Mobility

Performance Risks

Cost risk

Mobility

Performance Risks fouling* fouling* fouling* fouling*

Cost risk

Mobility

Performance Risks fouling* fouling* fouling* fouling*

Cost risk

Mobility

Performance Risks fouling* fouling*

Cost risk

Mobility

Oil water separator

Hydrocylcone

Lime softening

Chemical 

Precipitation

Electrocoagulation

Dissolved air 

flotation

Aeration and 

sedimentation

Biological 

Treatment

Sand or multimedia filtration

Bag filters

Ion exchange

Walnut shell filter

actvated carbon

Organoclay

Fentons

Ozone

Chlorination

Potasium 

permagenate

Microfiltration

Ultrafiltration

Nanoflitration

Reverse Osmosis

Electrodialysis

Coalescence of oil and removal through flotation

Utlilized centrifugal force to separate solids and oils 

from water

Addition of lime and soda ash to water to achieve 

hardness removal

Coagulant addition to develop floc, removing TSS, O&G, 

and di-/trivalent ions

Uses electricity to dissolve an iron or aluminum 

electode, and developing floc.

Clarification of water by contact with minute 

bubbles, floating air/floc mass to surface 

Aeration to oxidize reduced species to less soluble 

state. 

Process where microbes degrade organics.

Vessel filled with sand or other granular media to remove 

TSS or colloids from water passed through it

A dead-end filter made of mesh material of specific 

micron size to remove TSS.

The reversible exchange of ions between the liquid 

and a solid resin

Filter made from crushed walnut sheels for O&G 

removal

A highly adsorbent fomr of carbon used to remove 

dissolved organic matter from water

Bentonite clay modified with quaternary amines, 

used as an adsorbent for O&G

Advanced oxidation using Fe and H2O2 to produce 

hydroxyl radicals to degrade organics.

A strong oxidizing agent able to degrade organics.

A strong oxidizing agent, although not as strong as 

ozone.

Method for separating water from dissolved salts by passing 

feedwater through a semipermeable membrane at a pressure 

greater than the osmotic pressure.

Separation of ionic components using semipermeable ionselective membranes operating in an electric field

Used for oxidation of iron and manganese

Low pressure membrane filtration process for removing TSS 

and colloids > ~0.1um (cutoff varies by membrane)

Low pressure membrane filtration process for removing TSS 

and colloids >~20nm (cutoff varies by membrane)

Medium pressure membrane process for removing 

di- and tri-valent ions and species > ~1nm

Each of the options was evaluated for potential risks with performance individually and upon integration into a process. Costs risks were based on 

overall process satisfying the $2/bbl feed treatment cost criterion. Mobility risks were for incorporating the technology and the integrated process 

in a mobile rig.
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3.4 Task 4: Evaluate key Pretreatment and Membrane Processes in benchscale experiments

3.4.1 Objectives and Approach

The specific objectives were: 

 Evaluate pretreatment methods and RO/NF membranes for treating frac flowback 

water via bench-scale experiments 

 Make a go/no-go decision based on whether pretreatment methods for effective removal of the contaminants are technically feasible and cost-effective. 

3.4.2 Bench-scale experimental approach

The extent of removal of contaminants and water recovery will depend on the flowback concentration and the desired product concentrations for the Product options 1-4 described in 

Figure 30. The various mechanical, chemical and membrane technologies that were identified to be  ̳Green‘ in Task 3 were evaluated via bench-scale laboratory experiments. The experiments were conducted initially with simulated frac water (pure water mixed with known 

concentrations of one or more target contaminants) and later with the frac flowback water 

samples obtained from the Woodford shale. 

The bench-scale experiments involved the evaluation of various additives, such as coagulants, flocculants, softening chemicals, sorbents, etc., various operating conditions, such as 

pH, concentrations, mixing times, settling times, temperatures, flow rates, etc. various separation equipment, such as filters, mixed-media deep filtration beds, cross-flow filtration, microfiltration, ultrafiltration, nanofiltration, reverse osmosis, etc.

Essentially, the key process steps for treating the frac flowback waters can be categorized as 

follows:-

 Clarification: Removal of suspended solids, oil & grease, microbiologicals, and dissolved organics (in some cases). Removal of Fe++ may be included here since oxidation to Fe+++ occurs readily in the presence of oxygen and Fe+++ can cause precipitation and fouling in downstream applications either during re-use as Product-1 or in 

the desalination membrane modules used for producing Product-3 or Product-4..

 Softening; Removal of ―hardness‖ ions, such as Ca, Mg, Ba and Sr, which may cause 

precipitation and plugging in downhole applications during re-use as Product-2 or in 

the desalination membrane modules used for producing Product-3 or Product-4. 

 Desalination: Removal of dissolved salt ions, mainly NaCl using membranes used to 

produce product waters suitable for re-use as Product-3 or surface discharge as 

Product-4.

In the sections below, the approach for treating the flowback waters and the associated 

bench-scale experiments and results are described for the key process steps.
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3.4.3 Process Step: ―Clarify‖

The purpose of this step is to remove contaminants in the flowback water to satisfy the 

downstream applications, either as Product-1 (cf. Figure 33) or as feed to membrane desalination processes. Note that the specifications for the membrane applications may be more 

stringent than for frac re-use with Product-1. 

Various coagulants were evaluated at different operating conditions. Some of these benchscale experiments with certain coagulants for the ―composite‖ Days 1-14 water from Site-1

are shown for illustration in Figure 35. We observe that coagulation is effective at significantly reducing turbidity, TOC, Fe and Mn, as required for Product-1. 

Figure 35. Clarification of frac flowback waters. Results of bench-scale experiments with the 

―composite‖ Days 1-14 Woodford Site-1 sample.

In Figure 36, the results of coagulation experiments with the Site-2 Day-26 sample are 

shown. For this experiment, the sample from the bottom of the 55-gal drum which had significant solids content was deliberately chosen to illustrate the effectiveness of the coagulation conditions. We observe that even this worst portion of the flowback water was effectively treated by these conditions.

Clarify: Evaluation of coagulants

Sample: Site-1 “composite” Days 1-14 water

Procedure:

•Rapid mix coagulant for 

2 mins

•Mix Polymer Flocculant 

(10 ppm) for 1 min

•Slow mix for 5 mins

•Settling 20 mins

Coagulants effectively remove target contaminants

-

20

40

60

80

100

120

140

160

0 200 400 600 800 1000

Coagulant concentration, ppm

Turbidity, NTU

FeCl3, pH=6.8 FeCl3, pH=8

PAC, pH = 6.8 GE1172 250ppm

-

5

10

15

20

25

30

35

40

45

0 200 400 600 800 1000

Coagulant concentration, ppm

TOC, ppm

FeCl3, pH=6.8 FeCl3, pH=8

PAC, pH = 6.8 GE1172 250ppm

-

5

10

15

20

25

30

0 200 400 600 800 1000

Coagulant concentration, ppm

Fe, ppm

FeCl3, pH=6.8 FeCl3, pH=8

PAC, pH = 6.8 GE1172 250ppm

-

10

20

30

40

50

0 200 400 600 800 1000

Coagulant concentration, ppm

SiO2, ppm

FeCl3, pH=6.8 FeCl3, pH=8

PAC, pH = 6.8 GE1172 250ppm

-

5

10

15

20

25

30

35

0 200 400 600 800 1000

Coagulant concentration, ppm

Ba, ppm

FeCl3, pH=8 PAC, pH = 6.8

GE1172 250ppm

Coagulant 1 Condition 1

Coagulant 1 Condition 2

Coagulant 2

Coagulant 3
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Water: Site-2 Day-26 Raw Bottom of jug

Clarify: Evaluation of coagulants

floc

100 μm 100 μm NTU = 2098

TSS = 776

TOC = 18.4

NTU = 5.2

TSS = 136

TOC = 13

Day 26 Bottom of jug

250ppm Coagulant-3 & 10ppm Flocculant

Settled 30 minutes

Figure 36. Clarification of frac flowback waters. Results of bench-scale experiments with the Day26 Woodford Site-1 sample.

In Figure 37, the results of coagulation experiments with the Site-1 Day-1 sample are shown. 

As seen in Figures 16 and 17, the Day-1 sample had the highest total suspended solids (TSS) 

and very high total organic carbon (TOC) values relative to the ―composite‖ Days 1-14 from 

Site-1 or the Day-26 sample from Site-2. We observe in Figure 37 that the coagulation conditions that were successful previously with the ―composite‖ Site-1 Days 1-14 sample in Figure 

35 and Day-26 Site-1 sample in Figure 36 were not as successful with this Site-1 Day-1 sample. 

Figure 37. Clarification of frac flowback waters. Results of bench-scale experiments with the Day1 Woodford Site-1 sample. 
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However, when the supernatant liquid after flocculation and settling was passed through a 

novel GE-ultrafiltration membrane, the desired clarification was obtained, as shown in Figure 

38. The technique was also effective for the Day-26 sample from Site-2, although such extra 

clarification may not be necessary in this case.

Raw

Cross flow system

GE-UF membrane

Clarify: Coagulation + UF 

Coagulated + 

GE-UF filtrate

NTU = 207

TSS = 238

TOC = 130

NTU = 90

TSS = 226

TOC = 46

NTU = 0.6

TSS = 34

TOC = N/D

Coagulated with 

500ppm Coagulant-3 + 

5ppm Flocculant

Settled 30 mins

Water: Woodford 

Site-1 Day 1

Raw Coagulated 

only

NTU = 2098

TSS = 776

TOC = 18.4

NTU = 5.2

TSS = 136

TOC = 13

NTU = 0.17

TSS = 42

TOC = 6

Coagulated & 

GE-UF filtrate

Water: Woodford Site-2 

Day 26 “bottom of drum”

Encouraging lab results for oily & dirty water clarification 

with novel GE-UF

Figure 38. Clarification of frac flowback waters with coagulation and ultrafiltration. Results of 

bench-scale experiments with the Site-1 Day-1 and Site-2 Day-26 Woodford samples. 

3.4.3.1 Removal of Organics

The sources of organic compounds in the frac flowback water were described in Section 3.3.2 

and were broadly classified as Free Oil & Grease , Dissolved Organics and Volatile Organics.

In the data shown in Figures 35-38, we observed that it is relatively difficult to reduce the TOC 

for the Site-1 Day-1 water compared to the Site-2 Day-26 and Site-1 ―composite‖ waters. It is 

very likely that the nature of the organics for the Site-1 Day-1 water is significantly different 

compared to the other later flowback samples, perhaps more contaminated by the Free Oil & 

Grease components. 

For better understanding, various sorbents were evaluated. In Figure 39, the sorbent performance from isotherm experiments are plotted for similar experiments conducted with the 

Site-1 Day-1 sample and Site-1 ―Composite‖ Days 1-14 sample. Interestingly, with the Day-1

sample, we observe two distinct regions in terms of efficacy of organics removal: (a) ―easy‖ to 

remove organics from ~180 ppm to ~30 ppm TOC, and (b) ―difficult‖ to remover organics 

down from ~30ppm TOC. This suggests to possibly different natures of the two sets of organ-
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ics in the flowback sample. Moreover, we observe a similar behavior with the ―Composite‖ 

Days 1-14 water sample, with an ―easy‖ to remove group down to 20~30 ppm TOC and a 

more ―difficult‖ to remove group down from ~20 ppm TOC. Very interestingly, the slopes for 

the ―easy‖ regions of the adsorption isotherms for the two samples shown in Figure 39 are 

same, which indicates that the ―composite‖ sample may be considered to be a diluted version of the Day-1 sample in this regard. 

Figure 39. Removal of organics from Woodford shale flowback samples. Comparison of adsorption 

isotherms of three sorbents for the Site-1 Day-1 sample and ―Composite‖ Days 1-14 sample.

3.4.3.2 Nature of the organics in frac flowback waters – novel analytical technique

The organic content of the flowback waters were initially measured by two techniques, 

namely via ―hexane extraction‖ and by Total Organic Carbon (TOC), as reported in Figure 17. 

The ―Hexane Extractables‖ method gives a measure of the components that are hexane soluble and is a good indicator of the free Oil & Grease content of the frac flowback water. The 

TOC measures the amount of combustible organic carbon present in the frac flowback water 

and is an indicator of dissolved and undissolved organics, including non-volatile and volatile 

compounds. 

The ―hexane extractables‖ and TOC methods are used routinely for estimating the organic 

content in waste waters. However, to understand the nature of these organic contaminants, 

we have used another technique developed by Hans Grade at GE Global Research that uses 

a 2-column gas chromatography (GC) method for separation of the components based on 

polarity and boiling point, followed by analysis with a Time of Flight Mass Spectrometer. In 

8 /

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10-15-2010

Organics removal with sorbents: Lab-scale experiments

Two “oil” groups – easy vs difficult to remove with sorbents!

Day 1 Padgett water

-

20

40

60

80

100

120

140

160

0 50 100 150 200

TOC, Ce (mg/L)

TOC absorbed/g sorbent, qe (mg/g)

Nuchar SN20

Norit CASP

Norit S-51FF

Composite Padgett water

0

20

40

60

80

100

120

140

160

0 20 40 60 80 100 120 140 160 180 200

TOC, Ce (mg/L)

TOC absorbed/g sorbent, qe (mg/g)

Nuchar SN20

Norit CASP

Norit S-51FF

Adsorption Isotherms 

Easy to 

remove 

group

Difficult to 

remove 

group

Water: Woodford Site-2 Day 1 Water: Woodford Site-2 “Composite” Days 1-14

Sorbent 1

Sorbent 2

Sorbent 3

Sorbent 1

Sorbent 2

Sorbent 3
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this technique, 100 ml of the water of interest is mixed intimately with 20 ml of methylene 

chloride to allow extraction of the organic contaminants into the methylene chloride phase. 

After separation of the two layers, the organic contaminants are analyzed by the GCxGC MS 

method. A pure methylene chloride with 10 ppb methyl eiosonoate was used as the Control 

sample for comparison.

In Figure 40, the GCxGC MS plots for the Day-26 raw frac sample and the Control sample are 

shown in the 2-dimensional format of Polarity x Boiling Point. We notice the location of different hydrocarbons on the plot for Site-2 Day-26 water.

The GCxGC-MS data may also be plotted in a 3-D format to indicate the magnitude of the 

response, as shown in Figure 41 for the Control sample. It should be noted that although the 

magnitude could be an indicator of the concentration of the organic contaminant (or fragment), it may be influenced by a variety of others factors. Hence, these 3-D plots are best 

used as qualitative indicators.

Figure 40. GCxGC-MS 2-D plots for the Control and Day-26 (frac) raw water. Note the presence of 

hydrocarbons of various polarities and boiling points (molecular weight) in the Site-2 Day-26 sample. 
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Similarly, GCxGC-MS 3-D plots for the Site-2 Day-26 and Site-1 Day-1 frac water field samples 

are shown in Figure 42. The corresponding data for the hexane-extractables and TOC methods shown in Figure 17 are also reproduced in Figure 42. We observe that the Site-1 Day-1 

sample has more polar hydrocarbon compounds and also higher intensities. This corresponds to higher total organic carbon in the Site-1 Day-1 raw water compared to Site-2 Day26 sample.

Hydrocarbon removal analysis

Hans Grade, 

GE GRC

Novel sample analysis based on GC x GC + ToFMS technique 

(Instrument: LECO Pegasus 4D ) Hexane Extractables

Total Organic 

Carbon, ppm

Site-1 

Days 1-14

Site-2

Day 26

Flowback time, days

Figure 41. GCxGC-MS 3-D plot for the Control methylene chloride (with 10 ppb methyl eiosonoate). 

Figure 42. GCxGC-MS 3-D plot for the Day-26 and Day-1 frac water field samples. Day-1 sample 

has more polar hydrocarbons and in general, higher intensities corresponding to the overall 

higher TOC content.
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Evaluation of various treatment methods for removing organics in frac flowback waters

A series of 1-liter jar experiments were conducted with the frac flowback field samples using 

a variety of coagulants, flocculants, adsorbents, and oxidants and for various operating conditions (time, mixing conditions). Samples were collected during these experiments and analyzed by the above mentioned GCxGC-MS method to evaluate the effect of the treatment 

method on appearance or disappearance of organic species. For example, in Figure 43, the 

GCxGC-MS plot for the water sample after Treatment 1 is compared to the original raw Site-2 

Day-26 water sample. We observe that the Treatment 1 introduced certain species that 

were shown to correspond to surfactant molecules.

Similarly, Treatment method 5 and Treatment method 13 are compared in 2-D GCxGC-MS 

plots in Figure 44. We observe that Treatment 5 has effectively removed a portion of the hydrocarbons found in the original Day-26 raw water, while Treatment 13 has significantly diminished the intensities of the hydrocarbon peaks relative to raw and after Treatment 5.

The effect of operating time for Treatment #13 on the level of organic contaminants in the 

frac flowback water is illustrated in Figure 45. We observe that the intensities of the peaks 

corresponding to organic contaminants diminishes significantly for longer operating times.

From the above results it is clear that the novel GCxGC + ToFMS analytical technique provides 

a powerful means to evaluate the effect of various treatment methods on the presence and 

disappearance of various organic species. However, it should be noted that the nature of 

this research is still in its infancy. More work is required to quantitatively link the effectiveness of any treatment method on the removal of particular organic species that are undesirable for product quality specifications for frac re-use or impact on desalination membrane 

fouling.

Figure 43. Effect of Treatment#1 on the organic contaminant levels of the Day-26 frac flowback water sample. Observe the appearance of peaks associated with surfactant molecules.
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GE Global Research

Figure 44. Comparison of GCxGC-MS 2-D plots for Day-26 raw water and after Treatment#5 and Treatment#13. 

Figure 45. Comparison of GCxGC-MS 3-D plots for Day-26 raw water and after Treatment#13 for 

two different times. 
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3.4.4 Process Step: ―Soften‖

The removal of ―hardness‖ ions, such as Ca, Mg, Ba and Sr, may be accomplished by precipitation methods, such as lime softening or membrane methods, such as nanofiltration that 

selectively reject the divalent and trivalent ions. The lime-softening process, if properly designed would provide water recoveries in the range of >95%, which satisfies the requirements in Figure 30. We evaluated nanofiltration via modeling with the GE Winflows membrane system design and simulation software 20 using technical performance data for GE‘s 

nanofiltration membranes. For the frac feed water sample analyses reported in Table 3, although the removal of hardness was >80%, the water recoveries were in the range of 

50~80%, which is much lower than the product specifications in Figure 30. Hence, we have 

focused our efforts on evaluating only lime-softening for softening frac flowback waters.

Lime softening has been industrially used for more than a hundred years. It may be operated 

in the ―cold‖ mode or ―hot‖ mode. Although the ―hot‖ mode requires less chemicals, choossing the ―cold‖ mode will provide robustness to our conceptual process in handling frac flowback waters from a variety of frac sites. 

The principles and process of lime softening are best explained on the GE Water website21. 

Hence, only a summary is provided below.

When hydrated lime, Ca(OH)2, is added to the water being treated, the Mg++ ions are precipitated as Mg(OH)2. Noncarbonate or permanent calcium hardness, if present, is not affected 

by treatment with lime alone. The frac flowback water sample analyses shown in Table 3 

indicate a high level of noncarbonate hardness – the total hardness/‖M‖ alkalinity ratio is ~4-

5 for the three samples under consideration. In such cases, soda ash (NaCO3) is added to 

precipitate the Ca++ as CaCO3.

Bench-scale experiments were conducted by addition of Ca(OH)2 and Na2CO3 to 1-liter jars 

containing the frac flowback sample. The results for the Site-1 Day-1 and Site-1 ―Composite‖ 

Days 1-14 samples are shown in Figure 46. Similar data was obtained for the Site-2 Day-26 

sample (reported later in Table 5). We observe that lime softening conditions are able to significantly reduce the hardness levels to meet the specifications for Product-2 and the pretreatment levels required for desalination membrane processes. 

The process equipment required for precipitation softening are vessels with mixing equipment to contact the feed water with the lime initially and then with soda ash. After sufficient 

contacting, the precipitate is allowed to settle and the clear liquid is filtered. The settled solids or sludge needs to be compacted to reduce the water content and lower the waste handling and disposal costs. A combination of sludge compaction and filtration is used typically 

to obtain wastes containing ~30% solids. Further reduction of the water content may require 

some means of evaporation. The relative costs of locating such sludge drying processes onsite versus the waste disposal costs need to be weighed on an individual frac flowback site 

basis. 
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Clarify + Soften: Lab-scale experiements

Site-1 “Day 1” 

raw

25 min 

settling

-

1,000

2,000

3,000

4,000

5,000

6,000

Padgett

"Day 1"

raw

UF only Lime

only

Lime + UF

Total Hardness, mg CaCO3/l TSS, mg/l

0

50

100

150

200

250

pH

adjusted to

6.8 and

unfiltered

through GM (UF

flat sheet)

Lime

softened

not settled

Lime

softened

settled

Lime

softened

(UF flat sheet)

 Fe, ppm

 Ba, ppm

 Sr, ppm

 SO4, ppm

 SiO2low, ppm

 SiO2-Total, ppm

Site-1 Day 1 water

Site-1 “Composite” water

Softening feasible for Woodford frac flowback water samples

Lime + 

Soda Ash

Raw

Figure 46. Clarification of frac flowback waters with coagulation and ultrafiltration. Results of 

bench-scale experiments with the Site-1 Day-1 and Site-2 Day-26 Woodford samples. 

The expected water recovery after such a lime-softening process is expected to be >95%.

Mass balances were conducted for a 50-gpm frac flowback water treatment system to determine the amounts of lime & soda ash required and the amount of waste stream generated. 

For the Site-2 Day-26 stream shown in Table 3, the amounts of Ca(OH)2 and Soda Ash required per bbl of feed water would be 0.38 lbs and 0.56 lbs, respectively on a dry basis. The 

amount of sludge (30% solids) produced would be 3.68 lbs/bbl feed processed, i.e. 3.2 short 

tons/day. Assuming disposal costs of $70/ton at a non-hazardous disposal site located within 50 miles and transportation costs of $5/mile, the waste disposal costs are estimated to be 

in the range of $0.15/bbl of feed.

For the Site-1 Composite Days1-14 sample, which contains a higher level of hardness, the 

amounts of Ca(OH)2 and Soda Ash required per bbl of feed water would be 0.50 lbs and 1.91 

lbs, respectively on a dry basis. The amount of waste generated would be 7.84 lbs/bbl water 

processed, i.e. 6.7 short tons/day. The waste transportation and disposal is estimated in the 

range of $0.30/bbl of feed.
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3.4.5 Desalination Membrane performance

For Product-3 and Product-4, that require desalination to TDS levels <20,000 ppm and <500 

ppm, respectively, the performance of membrane desalination was evaluated via modeling 

using the GE Winflows membrane system design and simulation package20. Various membrane materials and system design configurations were considered to increase water product recovery. The methodology is illustrated in Figure 47 for a feed solution with composition 

similar to that obtained after pretreating (lime softened and filtered) Site-2 Day-26 sample. 

This feed rate was 50 gpm and contained 35K ppm TDS, while the desired product has TDS 

<500 ppm, i.e. meeting Product-4 quality requirements (cf. Figure 30). We observe that by 

appropriate choice of membrane system designs, it is possible to increase the recovery from 

49% using the standard seawater-desalination design to as high as 61.5%. The retentate 

concentration correspondingly increased from 68K ppm to 90K ppm TDS for these conditions. 

This has implications on overall system recovery and costs of the overall flowback water recovery process, as will be discussed under Task 6. The increase in the number of stages and 

process complexity increases capital equipment costs in terms of pumps, membrane modules, interconnected piping and control equipment. Hence, trade-offs of higher recovery vs. 

higher equipment costs needs to be considered. 

Figure 47. Maximizing RO-desalination water recovery of pretreated Site-2 Day-26 flowback water 

via simulation studies using GE Winflows software20.
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3.4.6 Process Flowsheets

Using the information from the bench-scale experiments for the various pretreatment steps, 

detailed conceptual flowsheets for the treatment processes were constructed for each of the 

Products 1-4 under consideration. For the case of producing Product-1 quality water, the 

conceptual flowsheet is illustrated in Figure 48.

Figure 48. A conceptual process flowsheet for treating frac flowback waters to produce waters 

meeting Product-1 quality specs (cf. Figure 30). 

Similarly, process flowsheets were constructed to meet the respective quality requirements 

for Product-2, Product-3 and Product-4. These were evaluated for technical performance, 

costs and mobility for a 50-gpm feed (frac flowback) mobile rig system. Technical performance evaluation included mass and energy balances, including waste generation and handling. Costs included capital expenses for equipment and assembly, and operating expenses 

for amortization of capital equipment, rig-setup labor, chemicals, membranes, power, and 

waste removal. Mobility included the preliminary assessment of the rig configurations suitable to treat 50 gpm of the frac flowback water. 

The treatment costs to produce Product-4 - the most challenging and most expensive - is 

illustrated in Figure 49. As described earlier, treatment costs include CSetup (Cost of mobile rig 

transportation and setup at the frac site) and CProcess (Cost associated with the capital and 

operating expenses related to the process steps). It does not include the cost of product- and 

concentrate-disposal. The labor costs associated with setting up the mobile rig are included 

in CSetup and thus in the CTreatment value. However, the rig operating labor for treating flowback 

water has not been included since these costs may be accounted differently by different producers as the rig may be run by operators handling multiple responsibilities at the frac site.

We observe the following in Figure 49:

10 /

GE GRC 

10-15-2010

Removal of Free Oil, TSS, Microbiologicals, TOC

Coagulant

Flocculant

Sand bed 

Filter

Backwash 

water

Product water to 

meet Product-1 

specs

Screen

Raw 

water

Oily water for 

disposal

Waste solids 

for disposal

Process Concept for Product 1

Clarifier
71

GE Global Research

 The treatment cost, CTreatment <$2/bbl feed, which was the target for our verification of 

success criteria (cf. Figure 32)

 Nearly 75% of the operating costs are related to ―fixed‖ charges (capital equipment 

related and rig transportation & setup), 18% due to chemicals and solid wastes disposal, while cost of replacement membranes and electricity costs were only 2% and 

5%, respectively. This indicates that for such low throughput mobile rigs, optimizing 

membrane performance to reduce power consumption will not have significant impact on the overall economics. What really matters is that the overall water recovery 

is improved while keeping the system capital costs low.

Operating cost breakdown for 50 gpm

mobile membrane rig

Equipment 

transport + setup

CTreatment = Csetup + Cpretreatment 

Cwaste_disposal + 

Cmembrane process

Feed Pretreatment Membrane

Waste

Product: 

Permeate 

Concentrate

Waste Disposal

Note: Excludes rig operating labor, 

Concentrate- & Product-disposal

Membranes and Electicity

costs only 7% of overall 

operating costs for such 

small throughput rigs

Treatment costs : <$2/bbl feed 

50 gpm

Figure 49. Operating cost breakdown for a 50 gpm mobile membrane rig capable of producing 

<500 ppm TDS product

3.4.7 Conclusions from Task 4:

The results of the bench-scale experiments, membrane system simulation and system cost 

analysis indicated the following in relation to the verification of success criteria for this project (cf. Figure 32):

 Technical Performance: There is a high level of confidence that the conceptual processes 

will be effective to yield the Products-1, -2, -3 and –4 of desired quality since these process flow schemes were constructed based on the bench-scale experimental studies on 
72

GE Global Research

the individual separation technologies using actual frac flowback samples. Many of the 

initial concerns were mitigated by appropriate choice and verification of process operating conditions in the lab-scale experiments.

 Cost Performance: The estimated costs for the four product options were within the cost 

criterion of < $2/bbl that was established in Task 2, and in line with preliminary feedback 

on customer expectations. The cost estimations were based on reliable values obtained 

either from vendors or internal cost information for the desired equipment. Other cost 

factors, such as costs of electricity, type and cost of labor, waste handling & disposal, 

were also obtained either from appropriate vendors or internal cost information. 

 Mobility Performance: Based on vendor information on sizes and operations of the various equipment identified for the conceptual processes, and internal data on mobile rig 

operations, 50-gpm mobile rig configurations may be achievable for the four products 

under consideration. 

Based on these technical-, economic- and mobility-feasibility analyses on currently available 

customer information for product quality and cost information, and the supporting lab-scale 

experimental results, the recommended course of action for the critical go/no-go decision 

was to go ahead with the project towards Tasks 5 and 6.

3.5 Task 5: Obtain bench-scale experimental data suitable for process 

modeling

3.5.1 Objectives and Approach

The objectives were:-

 Obtain membrane performance parameters necessary for system performance 

modeling.

 Demonstrate the efficacy of the downselected pretreatment methods to treat the 

field samples for low fouling of the RO-membranes during desalination.

Desalination experiments were conducted in the membrane-module testing rig shown in Figure 50. The rig consists of a feed tank, a high pressure pump, a membrane module housing, 

and relevant pressure, flow, conductivity and temperature sensors. Water is pumped from 

the feed tank through the membrane module inside the housing. A portion of that feed water 

permeates through the membrane (called ―permeate‖). The remaining portion (called ―retentate‖) is returned to the feed tank. A cooling bath and appropriate heat exchange equipment 

ensure that uniform temperature is maintained during the entire course of the experiment 

(note that the pumping energy results in a significant temperature rise of the re-circulating 

water).

The independent parameters are:

 Feed composition

 Feed rate
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GE Global Research

 Pressure

 Temperature

 Membrane module parameters: Membrane type, Surface area, Internal geometry

The dependent & measured parameters are:-

 Permeation rate 

 Permeate concentration

 % recovery per pass

Figure 50. Membrane module testing rig for conducting desalination experiments with pretreated 

field frac flowback samples at GE Global Research.

Modes of operation:

 Closed circuit: The permeate is returned to the feed tank. In this case, the net concentration in the feed tank essentially remains constant since the retentate and permeate streams are re-mixed. This mode is useful for determining the stability of the 

membrane performance as a function of time. We used this mode to evaluate the 

possible fouling of the RO membranes over a period of 24 hours, as described below.

 Open circuit: The permeate is not returned to the feed tank. In this case, the loss of 

desalinated permeate volume results in a net increase in TDS concentration in the 

Feed tank 

(15 lit)

Control 

panel

Pump

Membrane 

modules
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feed tank. This mode is useful for determining the membrane performance properties as a function of feed concentration. 

The membrane performance parameters of interest are:

 Water-flux parameter: This is frequently referred to as ―A-value‖ in reverse osmosis 

literature. A high value of this parameter is preferred as it implies a low membrane 

surface area requirement for the given separation duty, and thus lower costs and 

smaller footprint for the ultimate application. Conversely, for a given membrane 

module configuration (fixed area), a high A-value implies lower pumping pressure requirements.

 Salt-flux parameter: This is frequently referred to as ―B-value‖ in reverse osmosis literature. A low value is preferred for this parameter as it implies low permeation of 

the salt species through the membrane, which results in a more purified permeate 

product.

 Salt-rejection parameter: This parameter is an indicator of the separation efficiency 

of the RO membrane at the operating conditions. A high value is preferred as it yields 

a more purified permeate product.

These parameters are used for modeling large-scale membrane module performance and 

also for membrane-system level performance modeling.

3.5.2 Membrane performance parameters vs. Feed composition

The field sample Site-2 Day-26 was subjected to appropriate pretreatment process steps to 

produce 14 liters of solution (approx. 95% recovery) with a TDS of ~33,000 ppm. Similarly, the 

field sample ―Day-1‖ was subjected to appropriate process steps to produce 7 liters of solution (approx. 95% recovery) with a TDS of ~20,000 ppm. Desalination of this treated water 

was performed using spiral wound modules (2‖ diameter, 4.5 ft2 membrane area) with highselectivity membranes that are typically used for seawater desalination to produce very low 

TDS permeate product (<500 ppm TDS).

The experiments were conducted in the open circuit mode to obtain the profiles of the desired membrane performance parameters as a function of feed composition. The permeate 

TDS for both of the field sample runs are plotted in Figure 51. For the Site-2 Day-26 sample, 

we observe that the feed concentration increased from 37,500 ppm TDS to 64,000 ppm TDS, 

with a net permeate recovery of 42% at an operating pressure of 800 psi. Further experimentation was stopped since the permeation flow rate was too low due to the high osmotic 

pressure of the feed solution as its concentration increased. For the Site-1 Day-1 sample, we 

observe that the feed concentration increased from 20,000 ppm TDS to 42,000 ppm TDS, with 

a net water permeate recovery of about 51%. Further recovery would have been possible 

but the experiment had to be stopped because of the low levels in the feed tank. Nevertheless, it is interesting to note the smooth nature and overlap of the permeate TDS vs. feed TDS 

profile for the two different pretreated field flowback samples in Figure 51, which is due to 
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the membrane properties and the cleanliness of the pretreated field frac flowback samples. 

We observe that the permeate TDS concentration rises rapidly as the feed TDS concentration

rises for this membrane.

Figure 51. Permeate TDS vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 liters 

of pretreated field frac flowback samples. See text for details.

The membrane performance parameters, namely water-flux, salt-flux and salt-rejection vs. 

Feed TDS concentration for these two pretreated field frac flowback samples are shown in 

Figures 52, 53, and 54, respectively.
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Figure 52. Water flux parameter vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 

liters of pretreated field frac flowback samples. See text for details.

Figure 53. Salt-flux parameter vs. Feed TDS for the 2‖ spiral wound RO module runs using 10~15 

liters of pretreated field frac flowback samples. See text for details.
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Figure 54. Salt-rejection parameter vs. Feed TDS for the 2‖ spiral wound RO module runs using 

10~15 liters of pretreated field frac flowback samples. See text for details.

As mentioned earlier, these parameters are useful for modeling large-scale membrane module performance and also for membrane-system level performance modeling. Similar data 

were gathered for other membrane types; especially those with higher flux (perhaps lower 

salt rejection) to yield lower quality (higher TDS) permeate suitable to meet the Product-3 

quality requirements (cf. Figure 30).

3.5.3 Evaluation of Desalination Membrane Fouling

The pretreated Site-2 Day-26 field frac flowback sample was used to evaluate the effectiveness of pretreatment on the fouling of a desalination membrane over a period of 24 hours. 

The parameters considered were the water-flux, salt-flux and salt-rejection. The results for 

the pretreated Site-2 Day-26 field sample were compared to those for pure 35,000 ppm TDS 

solution prepared with de-ionized water and pure NaCl. The membrane considered was the 

high-selectivity desalination membrane typically used for seawater desalination to produce 

very low TDS permeate product (<500 ppm TDS) in the spiral wound modules (2‖ diameter, 4.5 

ft2 membrane area) format. 

Experimental procedure:

For the Site-2 Day-26 field frac flowback sample, the fouling runs shown below in Figures 55-

57 were obtained over 24 hours by operating the system of Figure 50 in a closed circuit mode 

(Note that immediately following this operation, the system was operated in the open circuit 

mode to obtain the performance vs. feed TDS profiles reported previously in Figures 52-54). 
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After the Site-2 Day-26 sample run, the entire rig assembly shown in Figure 50 was purged 

and flushed with de-ionized water several times. A new membrane module containing the 

same membrane type and configuration, and manufactured at the same commercial facility

was installed in the membrane housing. This module was flushed with de-ionized water and 

other treatments were performed as per membrane manufacturer‘s recommendations. 

Then about 15 liters of the NaCl solution in de-ionized water was introduced and the solution 

was circulated through the system at low pressure to mix the feed solution in the system. 

The feed concentration was approximately 35,000 ppm TDS when high pressure of ~800 psi 

was applied and the permeation process was allowed to continue in the closed circuit mode.

The profiles of the 3 parameters of interest, namely water-flux, salt-flux and salt-rejection are 

shown normalized to the initial values for the pretreated ―Day-26‖ field frac flowback sample 

with 37,500 ppm TDS and the comparative 35,000 ppm TDS pure NaCl in de-ionized water in 

Figures 55, 56, and 57, respectively. 

Figure 55. Comparison of water-flux parameter change due to desalination membrane fouling for 

pretreated Site-1 Day-26 field frac flowback sample and pure NaCl/de-ionized water solution. 
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Figure 56. Comparison of salt-flux parameter change due to desalination membrane fouling for 

pretreated "Day-26" field frac flowback sample and pure NaCl/de-ionized water solution. 

Figure 57. Comparison of salt-rejection parameter change due to desalination membrane fouling 

for pretreated "Day-26" field frac flowback sample and pure NaCl/de-ionized water solution.
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The composition analyses for the Site-2 Day-26 before and after these 24-hour membrane 

fouling experiments are shown in Table 5. We observe the extent of hardness (Ca, Mg, Ba, Fe, 

Sr) removal by the pretreatment methods, and the permeate product quality (<500 ppm TDS).

Table 5. Composition analyses for the Site-2 Day-26 waters: raw, pretreated by softening, and 

after 24-hr membrane fouling test.

Observations and Conclusions: 

There is usually a decline of ~10% in water-flux parameter during the initial 6~ 8 hours (perhaps due to pressure compaction) as seen with the profiles of both the Site-2 Day-26 and 

control DI water with only NaCl (cf. Figure 55). But the trend after this initial period is important to observe from a fouling perspective. A steady decrease in performance over time 

would have indicated fouling of the membrane surface. However, we observe similar changes in performance over the initial 24-hour period for the two water solutions in Figures 55, 56

and 57. This indicates that there is insignificant fouling of the desalination membrane by the 

contaminants in the pretreated field frac flowback sample compared to the control sample. 

In other words, the downselected pretreatment conditions were effective in removing potential fouling contaminants from the field frac flowback sample (at least for this field sample 

and under these desalination experimental conditions).

Description Raw

lime softened, 

pH adjusted & 

filtered through 

1um

Final Retentate 

after RO Permeate

 "B, ppm 24.8 23 22.6 8.35

 "Ba, ppm 30.7 0.147 0.161 <0.1

 "Ca Hard, ppm 1160 37.4 34.7 <5.0

 "Cl, ppm 21600 21200 19700 243

 "Cond, ppm 54000 53500 50200 869

 "Fe, ppm 184 <0.5 <0.5 <0.5

 "HEM, ppm 2100 <6.0 <6.0 <6.0

 "Hard-Total, ppm 301 563 545 <10.

 "K, ppm 559 316 303 <5.0

 "M-alk, ppm 749 334 340 22.7

 "Mg Hard, ppm 1.19 518 503 8.21

 "Mn, ppm <0.6 <0.1 <0.1 <0.1

 "Na, ppm 16900 17200 16400 221

 "Ni, ppm 0.112 <0.1 0.309 <0.1

 "SO4, ppm 29 31 29 <1.0

 "SiO2 reactive, ppm 48 40 36.2 <2.0

 "SiO2-Total, ppm 185 39.9 39.9 <5.0

 "Sr, ppm 152 6.43 6.15 <0.1

 "TDS, ppm 32700 30700 29100 440

 "TOC, ppm 18.4 6 6.1 <1.0

 "TP, ppm 62.4 41.1 22.3 <4.0

 "TSS, ppm 776 18 71 <10.

Turb, NTU 2150 0.63 0.75 0.24

 "pH, ppm 7.36 7.54 7.84 8.34

 "NH3-Free, ppm 53 49.3 1.89
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3.6 Task 6—Develop system performance and cost models

3.6.1 Objectives and Approach:

The key objectives were:-

 Cost modeling for a mobile unit for low-TDS flow back water recovery

 Determination of economical ―cut-off‖ point for low-TDS water recovery process for 

flowback water treatment 

System cost models were developed for the mobile rig configurations for the four products 

under consideration (cf. Figure 30). However, in the following discussions, only the costs for 

membrane desalination systems used for Product-3 and Product-4 will be reported as they 

encompass the pretreatment steps used for Product-1 and Product-2 as well as the membrane desalination steps.

In Figure 58, the system configurations for the Conventional frac flowback disposal via underground Class II injection and the Flowback Water Recovery Process (FWRP) considered in 

this project are described. 

CTransport

R e-use 

water site

Fractional Recovery (x)

High TDS 

reject

“product ”

Gas for sales

Proppant

Well 

head

CRecovery = CTreatment + 

Cproduct Delivery

CDelivery $/bbl

CTreatment $/bbl

Flowback Water 

Recovery Process

CSWD

Interim Flowback 

Water Storage

Ctransport ~ $1-$20/bbl

Gas for sales

Proppant

Well 

head

Cconventional = CDisposal

= CTransport + CSWD 

CSWD ~$1-3/bbl

Interim Flowback 

Water Storage

System cost estimations

Conventional Disposal Flowback Water Recovery Process

Objectives: CFWRP < Cconventional for use application

Maximize Recovery (x)

Saline Water 

Disposal

Saline Water 

Disposal

CFWRP = CRecovery + CConc_Disposal $/bbl feed

Figure 58. System configurations for the conventional frac flowback disposal via underground 

saline water disposal and the Flowback Water Recovery Process 50-gpm mobile rig under consideration in this project.
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For this project we have considered the main driver for an FWRP to be financial and hence

the key economic criterion at any frac flowback site is assumed to be:

CFWRP < CConventional Disposal

However, it is likely that other non-economic drivers, such as regulatory mandates or public 

relations may also induce the producer to opt for the FWRP. In those cases, the objective 

may be to minimize CFWRP.

3.6.2 Membrane Desalination Mobile Rig – FWRP costs & economical ―cut-off‖ TDS

The cost correlations and parameters of interest were discussed in Section 3.2.12 and are 

summarized in Figure 59.

Cost correlations for mobile 50 gpm membrane rigs

Feed Pretreatment Membrane

Waste

Product: 

Permeate 

Concentrate

Waste Disposal: $70/ton wet cake

Concentrate Disposal

$2 ~$20/bbl concentrate

Product Delivery: $0.46/bbl product

Product Value: $0.22/bbl product

Equipment 

transport + setup $/bbl feed $/bbl product $/bbl concentrate

Equipment setup C_Equipment_setup

Pretreatment C_Pretreatment

Chemicals C_Chemicals

Waste disposal C_Waste

Membrane process C_Memb_fixed

Product delivery C_Product_delivery

Product value C_Product_value

Concentrate disposal C_Conc_disposal

Process Step

Cost parameters & units

CRecovery = (CSetup + CPretreatment + CMembrane +CChemicals + CWaste) + (CProduct Delivery - Cproduct Value)*X

CConc_Disposal = CDisposal*(1-X)

CFWRP = CRecovery + CConc_Disposal $/bbl feed

Recovery, X = Product/Feed

$/bbl feed

CDisposal = CTransportation + CSalineWD

CConventional = CDisposal

50 gpm

Chemicals

Figure 59. Cost parameters, units and correlations for the FWRP & Conventional processes described in Figure 58.

The extent of water product recovery expected from a membrane-based desalination system 

using the pretreatment processes developed in this project is plotted as a function of the feed 

TDS concentrations in Figure 60. Note that due to the membrane system designs evaluated 

in Task 4, it is possible to extend the retentate concentration to 90,000 ppm TDS compared to 

70,000 ppm TDS typically used in seawater desalination (cf. Figure 47), and thus achie ve 

greater water recovery at the same feed TDS concentration. This is illustrated for the Product-4 quality (500 ppm TDS) in Figure 60.
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Membrane System: Water recovery for different product 

requirements 

Pretreatment

Membrane

Feed

Waste

Concentrate Product

Xpretreatment = 98%

50 gpm yF

yPermeate

= 500 ppm

yConcentrate = 90,000 ppm

By-pass

yProduct = 500 ppm or 

20,000 ppm

Figure 60. Mass balance profiles for membrane desalination based FWRP for Product-3 (20,000 

ppm) and Product-4 (500 ppm). 

Note typical seawater desalination operates at yRetentate = 70K ppm TDS while choice of pretreatment & membrane system conditions for flowback recovery allow yRetentate = 90K ppm TDS, and 

thus higher recovery.

For Product-3, where the desired product TDS is less stringent at <20,000 ppm, we see much 

higher recoveries compared to Product-4. It is possible to achieve the Product-3 target by 

either:

 Alternative 1: Use high-flux low-rejection membranes that yield a permeate product 

with TDS < 20,000 ppm TDS (as originally conceived for this project) or 

 Alternative 2: Use high-selectivity but lower flux membranes typically used for seawater desalination that yield a permeate product with TDS <500 ppm and achieve 

the desired Product-3 target by blending with a by-passed portion of the feed to the 

membrane unit, as shown in Figure 60. 

During the cost estimations for the membrane systems described in Section 3.2.12, we had 

observed that for such small throughput (50-gpm) configurations the overall cost was dominated by the balance of plant rather than the number of membrane modules and power 

consumption (cf. Figure 49). Hence, from a practical perspective, it is prudent to design the 

conceptual process to produce the most stringent product, i.e. 500 ppm permeate, and then 

blend appropriately to meet the less stringent product quality. In other words, we select the 

Alternative 2 described above. 
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The main cost components, CRecovery, CConcentrate Disposal and the overall CFWRP are illustrated for a 

membrane desalination mobile rig producing Product-4 quality (500 ppm TDS) in Figure 61. 

These costs are plotted as a function of yF, the feed TDS concentration for an assumed value 

of CDisposal. These values are normalized with respect to CConventional. Thus, all regions with 

CFWRP/CConventional <1 would be economically attractive for FWRP. 

We observe in Figure 61 that that CRecovery decreases as yF increases because the extent of 

water recovery, X, decreases with increasing yF (cf. Figure 60), which results in lowering the 

contribution from product delivery costs. Interestingly, the slope of this decline is very small 

with increasing yF because the recovery costs are dominated by the Treatment Cost components. 

The CConcentrate Disposal increases as yF increases (and recovery decreases). The increase in 

CConcentrate Disposal is much sharper because CDisposal is usually much higher than CProduct delivery. The 

net effect of the profiles of CRecovery and CConcentrate Disposal is that CFWRP increases with yF. 

Membrane Recovery: Cost vs. Feed TDS

Pretreatment

Membrane

Feed

Waste

Concentrate Product

Xpretreatment = 98%

50 gpm yF

yPermeate

= 500 ppm

yConcentrate = 90,000 ppm

By-pass

yProduct = 500 ppm

1

Recovery, X

CRecovery = Csetup + Cpretreat + Cmembrane +

X*(Cprod delivery - Cproduct Value)

CFWRP = CRecovery + (Xpretreat -X)*CDisposal

CConventional = CDisposal

 $-

 $1.00

 $2.00

 $3.00

 $4.00

 $5.00

 $6.00

0 20,000 40,000 60,000 80,000

Costs/CConventional Disposal

Feed TDS concentration, ppm

C_FWRP, $/bbl feed

C_Recovery, $/bbl feed

C_Conc_Disposal, $/bbl feed

yProduct = 500 ppm; yPermeate = 500 ppm; yRetentate = 90,000 ppm; 

C_Product_Delivery = $0.46/bbl product; C_Product_Value = $0.22/bbl

product

CConventional

Figure 61. Cost components for the membrane-based FWRP: CRecovery, CConc_disposal and CFWRP for the 

operating and cost parameters developed in this project and for an assumed value of CDisposal.

Definition of economical “Cut-off” TDS for frac re-use: The value of yF where the CFWRP

crosses the CConventional line represents the economical “cut-off” TDS for that particular 

frac flowback site. 
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In Figure 62, the CFWRP for membrane-based desalination mobile rig for producing Product-3 

(20,000 ppm TDS) is compared to that for Product-4 (500 ppm) (previously illustrated in Figure 

61). We observe that the ―cut-off‖ TDS in this particular case is yF = 58,000 ppm TDS for 

Product-4 and yF = 65,000 ppm TDS for Product-3; the water recovery is 35% in both cases

(cf. Figure 60).

Membrane Recovery: Cost sensitivity to 

product TDS requirements

Pretreatment

Membrane

Feed

Waste

Concentrate Product

Xpretreatment = 98%

50 gpm yF

yPermeate

= 500 ppm

yConcentrate = 90,000 ppm

By-pass

yProduct = 500 ppm or 

20,000 ppm

CRecovery = Csetup + Cpretreat + Cmembrane +

X*(Cprod delivery - Cproduct Value)

CFWRP = CRecovery + (Xpretreat -X)*CDisposal

CConventional = CDisposal

 $-

 $1.00

 $2.00

 $3.00

 $4.00

 $5.00

 $6.00

0 20,000 40,000 60,000 80,000

CFWRP

/CConventional

yF, Feed TDS concentration, ppm

yProduct = 500 ppm TDS

yProduct = 20000 ppm TDS

yPermeate = 500 ppm, yRetentate = 90,000 ppm

1

Figure 62. Cost of membrane-based FWRP vs. feed TDS concentrations forProduct-3 and Product4 quality specifications.

This ―cut-off‖ TDS is a strong function of the CDisposal , the cost of transport and disposal of the 

saline water in Class II disposal wells. This is illustrated in Figure 63 for a membrane desalination mobile rig producing Product-4 quality (500 ppm TDS) where the CFWRP/CConventional Disposal 

ratio is plotted as a function of varying CDisposal at different values of yF. The points where the 

curves intersect the solid black line representing CFWRP/CConventional Disposal = 1 represent the ―cutoff‖ TDS at the yF and CDisposal values prevalent at the frac flowback disposal site under consideration. 
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Membrane System: Cost sensitivity to concentrate 

disposal costs

Pretreatment

Membrane

Feed

Waste

Concentrate Product

Xpretreatment = 98%

50 gpm yF

yPermeate

= 500 ppm

yConcentrate = 90,000 ppm

By-pass

yProduct = 500 ppm

Note: Benefits of penalty avoidance from local 

regulations have not been considered

Economic benefits of FWRP highly dependent on 

saline water disposal costs at shale plays

CRecovery = Csetup + Cpretreat + Cmembrane+

X*(Cprod delivery - Cproduct Value)

CFWRP = CRecovery + (Xpretreat -X)*CDisposal

CConventional = CDisposal

CFWRP

/CConventional

Figure 63. Profiles for CFWRP/CConventional for the membrane system vs. Concentrate disposal 

costs at varying feed TDS concentrations.

3.6.3 Hybrid Membrane+Thermal Mobile system – FWRP costs & economical ―cut-off‖ 

TDS

The extent of water recovery in the membrane desalination system is limited by the retentate 

concentration, as described earlier. Further water recovery from the retentate is possible via 

thermal desalination. This is illustrated in Figure 64 where a hybrid mobile system is considered for a Product-4 quality (500 ppm TDS). The frac flowback stream is first pretreated and 

then sent through a membrane desalination rig to produce a 500ppm permeate product. 

The retentate with 90,000 ppm TDS is then distilled in a mobile evaporator (such as that introduced by GE Water22 recently) to obtain distillate with <500 ppm TDS and a concentrate 

with 280,000 ppm TDS. As seen in Figure 64, such a configuration yields much higher recovery than the membrane system alone. For example, for a feed with yF = 35,000 ppm TDS, the 

hybrid system yields 85% recovery vs. 61% for the membrane rig alone. 
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Hybrid Membrane + Thermal Recovery: 

Water recovery 

Hybrid yields much higher water recovery than membrane alone. 

Pretreatment

Thermal

Feed

Waste

Concentrate Product

Xpretreatment = 98%

50 gpm yF

yDistillate

= 500 ppm

yConcentrate = 280,000 ppm

Membrane

yPermeae

Retentate = 500 ppm

yProduct = 500 ppm

Figure 64. Hybrid system incorporating pretreatment, membrane desalination and thermal distillation to yield Product-4 quality (500 ppm TDS); the 90K ppm TDS retentate from the membrane 

unit is distilled in the mobile evaporator to yield a 280,000 ppm TDS concentrate.

Of course, the capital and operating costs for this hybrid system would be greater than the 

membrane system alone. Hence, the CFWRP for the overall hybrid system will have to be considered. This is illustrated in Figure 65, where the CFWRP is plotted as a function of feed TDS, yF 

for the Membrane system only, Thermal (Evaporator) system only and Hybrid Membrane 

+Thermal system. For the assumed CDisposal value in Figure 65, the Membrane system is 

cheaper than either of the other systems when the feed TDS concentrations are low (<35,000 

ppm TDS in this case). The economical ―cut-off‖ TDS for the Hybrid case is higher at 82,000 

ppm TDS compared to 68,000 ppm TDS for Membrane system alone. More importantly, at 

these ―cut-off‖ TDS values, the water recovery is much higher at 69% for the Hybrid case vs. 

28% for the Membrane alone (cf. Figure 64).
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Hybrid Membrane + Thermal Recovery: 

Cost comparisons

yProduct = 500 ppm

Pretreatment

Thermal

Feed

Waste

Concentrate

Xpretreatment = 98%

50 gpm yF

yDistillate

= 500 ppm

yConcentrate = 280,000 ppm

Membrane

yPermeae

Retentate = 500 ppm

Product CFWRP

/CConventional

Figure 65. Cost profiles for the Membrane system alone, Mobile evaporator alone and the Hybrid 

membrane+thermal systems as a function of feed TDS concentration.

Again, as discussed earlier for the membrane mobile rig in Section 3.6.3, the economical ―cutoff‖ TDS is a strong function of the local CDisposal prevalent at the frac flowback site. For the 

Hybrid system the CFWRP/CConventional Disposal ratio is plotted as a function of varying CDisposal at different values of yF in Figure 66. The curves for the Hybrid case are compared with those for 

the Membrane alone (cf. Figure 63). 

We observe the following in Figure 66:

 The curves at the different values of yF for the Hybrid case are much closer than for 

the Membrane case alone due to the increased recovery for the Hybrid case

 The Membrane alone case is more economical for the lower CDisposal cases mainly due 

to the lower overall capital costs vs. the Hybrid case. However, the Hybrid case becomes more economically attractive as the CDisposal rises. 
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Hybrid Membrane + Thermal Recovery: 

Cost comparisons

Pretreatment

Thermal

Feed

Waste

Concentrate Product

Xpretreatment = 98%

50 gpm yF

yDistillate

= 500 ppm

yConcentrate

= 280,000 ppm

yProduct

= 500 ppm

Membrane

yPermeae

= 500 ppm

Membrane alone more economical for low disposal cost plays

Hybrid more economical at higher disposal cost plays

Retentate

CFWRP

/CConventional

CDisposal,$/bbl concentrate

Figure 66. Profiles for CFWRP/CConventional ratio vs Concentrate disposal costs for varying feed TDS 

concentrations.
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4 Summary and Conclusions

 Frac flowback water is not a uniform ―raw material‖ from a process development 

perspective:

o Flowback rates decrease sharply from as high 50~150 bbl/hr for the first 5-10 

days to <10 bbl/day beyond Day 30 of flowback. 

o Flowback composition varies considerably depending on the geological formation and operating conditions (e.g. chemicals introduced during the drilling 

and fracturing operations, diesel and compressor oils from pumps, etc.), and 

more importantly, as a function of time at the same well. 

 Applicability of low-TDS (< 45,000 ppm) recovery approach is ~90-100% for Fayetteville and Woodford shales, while limited to very early flowback in Barnett, Marcellus 

and other shales. 

 There is no clear consensus on product quality requirements for re-use in hydrofracturing. Based on feedback, 4 product options were identified, namely: Product-1 

based on ―Clarified only‖, Product-2 based on ―Softened only‖, Product-3 based on 

―Desal to 20Kppm TDS‖ and Product-4 based on ―Desal to <500ppm TDS‖.

 Lab-scale experiments showed that the identified ―pretreatment‖ techniques were 

successful in clarification and hardness-removal and able to meet the quality requirements for Product-1 and Product-2, and as pretreatment to the membrane desalination process.

 A novel GCxGC+ToFMS method for analysis of hydrocarbons was found useful in 

providing a qualitative understanding of the effect of pretreatment methods on the 

presence and disappearance of organic compounds in the treated frac flowback waters. 

 RO membrane fouling experiments conducted using commercially available 2‖ diameter spiral wound RO modules with pretreated flowback water showed identical water-flux and salt-rejection profiles as the control solution (35K ppm TDS NaCl in deionized water). This indicated the effectiveness of the downselected pretreated conditions in removal of potential membrane foulants (inorganic salts and colloidal inorganic and organic compounds).

 For Product-3 and Product-4, that require desalination to TDS levels <20,000 ppm and 

<500 ppm, respectively, various membrane system configurations were evaluated 

and optimized via performance modeling with GE Winflows software to increase water product recovery. For a feed solution composition similar to that obtained after 

pretreating (lime softened and filtered) Site-2 Day-26 sample, membrane system configurations were identified that increased the recovery from 49% using the standard 

seawater-desalination design to as high as 61.5%. The maximum retentate concentration correspondingly increased from 68K ppm to 90K ppm TDS for these conditions. The increase in capital costs due to additional pumps, membrane modules, interconnected piping and controls for the new configuration was more than offset by 

the increased water recovery when the overall FWRP was considered.
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 The estimated Treatment Costs for the four product options were within the cost criterion of < $2/bbl flowback, in line with preliminary feedback on customer expectations. The cost estimations were based on reliable values obtained either from vendors or internal cost information for the desired equipment. Other cost factors, such 

as costs of electricity, type and cost of labor, and waste handling & disposal, were also obtained either from appropriate vendors or internal cost information. 

 Membrane module and Electricity costs were only 2% and 5%, respectively, of overall 

operating costs for such small throughput (50 gpm) mobile rigs capable of producing 

Product-3 or Product-4. Nearly 75% of the operating costs are related to ―fixed‖ 

charges (related to capital equipment and rig transportation & setup) while chemicals 

and solids waste disposal accounted for the remaining 18%.

 Costs of the modeled overall Flowback Water Recovery Process (FWRP) were compared to those for the conventional saline water disposal method. For the desired 

economic consideration of CFWRP/CConventional  1 the ―cut-off‖ feed TDS concentration 

would depend on the disposal costs prevalent at the frac flowback site. Higher disposal costs would make FWRP attractive as seen in the sensitivity plots of 

CFWRP/CConventional vs. CDisposal at different feed TDS concentrations. These charts thus

provide a means of comparing the relative value of FWRP for a well flowback treatment opportunity based on prevailing disposal costs and anticipated flowback TDS 

levels. 

 The Hybrid membrane + thermal approach, wherein a 50-gpm pretreatment & membrane desalination rig is followed by a mobile evaporator to treat the retentate from 

the membrane unit, provides much higher water recovery (e.g. 85% vs. 61% for 

Membrane alone for a feed containing 35,000 ppm TDS). However, the Hybrid process costs more than individual process options alone due to the high fixed costs for 

such small throughput (50 gpm) systems. The Membrane alone case is more economical for the lower CDisposal cases mainly due to the lower overall capital costs vs. 

the Hybrid case. However, the Hybrid case becomes more economically attractive 

for the high CDisposal shale plays where local SWD sites are unavailable, thus leading to 

higher flowback water transportation costs for the conventional disposal method. 

Overall, based on bench-scale experiments on pretreatment and membrane desalination 

fouling conducted with typical frac flowback water samples from Woodford shale, membrane desalination system modeling, and cost analysis of the flowback water recovery process, we conclude:

 Technical Performance: There is a high level of confidence that the conceptual processes will be effective to yield the Products-1, -2, -3 and –4 of desired quality since 

these process flow schemes were constructed based on the bench-scale experimental studies on the individual separation technologies using actual frac flowback 

samples. Many of the initial concerns were mitigated by appropriate choice and verification of process operating conditions in the lab-scale experiments.
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 Cost Performance: The estimated Treatment Costs for the four product options were 

within the cost criterion of < $2/bbl in line with preliminary feedback on customer expectations. Using the CFWRP/CConventional  1 as the desired economic criterion, 

for Product-4 (500 ppm TDS), the ―cut-off‖ TDS for frac flowback water recovery is in 

the range of 20,000 ppm to 65,000 ppm depending on the local saline water disposal 

costs. The sensitivity plots of CFWRP/CConventional vs. CDisposal at different feed TDS concentrations provide a means of comparing the relative value of FWRP for a well flowback 

treatment opportunity based on prevailing disposal costs and anticipated flowback 

TDS levels. 

 Mobility Performance: Based on vendor information on sizes and operations of the 

various equipment identified for the conceptual processes, and internal data on mobile rig operations, 50-gpm mobile rig configurations may be achievable for the four 

products under consideration. 

 Hybrid membrane + thermal systems based on membrane desalination and a mobile 

evaporator may be attractive for treating Low-TDS frac flowback water for high disposal-cost plays. 

 It is believed that the parametric value assessment tool approach developed in this 

project to assess overall economic attractiveness of any Flowback Water Recovery 

Process (FWRP) relative to conventional disposal, and thus relating sensitivity of water 

recovery via treatment processes employed and product/reject disposal costs, will 

provide a rational basis for treatment process selection appropriate to well flowback 

characteristics and local disposal costs & regulations.
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APPENDIX: Water Chemistry of Drilling and Hydrofracturing Fluids

Drilling fluid

The drilling fluids used depend on the geology of the shale formation and the technology bias/experience of the operator. Most of the information is held proprietary and confidential. 

However, a good summary of the various components is provided at the DOE NETL website23. 

Information relevant to this project are reproduced below: 

 Drilling fluids or muds are made up of a base fluid (water, diesel or mineral oil, or a 

synthetic compound), weighting agents (most frequently barium sulfate [barite] is 

used), bentonite clay to help remove cuttings from the well and to form a filter cake 

on the walls of the hole, lignosulfonates and lignites to keep the mud in a fluid state, 

and various additives that serve specific functions.

 Mud Additives: Water-based muds (WBMs) would be preferable because they are not 

only inexpensive but the used mud and cuttings from wells drilled with WBMs can be 

readily disposed of onsite at most onshore locations. However, for difficult drilling situations, such as wells drilled in reactive shales, deep wells, and horizontal and extended-reach wells, WBMs do not offer consistently good drilling performance. For 

these types of drilling situations at onshore sites, the industry relies primarily on oilbased muds (OBMs). OBMs perform well, but may be subject to more complicated 

disposal requirements for onshore wells. OBMs contain diesel or mineral oil as the 

base fluid and may be harmful to the environment if directly discharged to a water 

source. 

 Synthetic-Based Muds (SBMs): These are nonaqueous fluids (other than oils) as their 

base. Examples of these base fluids included internal olefins, esters, linear alphaolefins, poly alpha-olefins, and linear paraffins. SBMs share the desirable drilling 

properties of OBMs but are free of polynuclear aromatic hydrocarbons and have lower toxicity, faster biodegradability, and lower bioaccumulation potential. The EPA has 

identified this product substitution approach as an excellent example of pollution 

prevention that can be accomplished by the oil and gas industry. SBMs drill a cleaner 

hole than water-based muds, with less sloughing, and generate a lower volume of 

drill cuttings. In offshore drilling, SBMs are recycled to the extent possible, while 

WBMs are discharged to the sea.

 New Drilling Fluid Systems: Drilling fluid companies are developing variations of fluid 

systems that are much more amenable to biotreatment of the subsequent drilling 

wastes. It is likely that companies will continue to develop fluids with suitable drilling 

properties that contain fewer components or additives that would inhibit subsequent 

break down by earthworms or microbes. In some circumstances, the constituents of 

the muds could actually serve as a soil supplement or horticultural aid.
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 Other developments in drilling fluids could lead to entirely different formulations. Drilling fluids based on formate brines have been suggested as being more environmentally friendly than traditional fluids. Formate brines are created by reacting formic acid with metal hydroxides. Common examples are cesium formate (HCOO-Cs+), potassium formate (HCOO-K+), and sodium formate (HCOO-Na+).

Alternate Weighting Agents: Substitution of some of the key components of drilling fluids with 

more environmentally friendly products could reduce mass loadings of potentially harmful 

substances to the environment. Barite is the most commonly used weighting agent. Other 

readily available weighting agents include hematite (Fe2O3) and calcium carbonate (CaCO3). 

Other wells have been drilled using ilmenite (FeTiO3) instead of barite as a weighting agent. 

Hydrofracturing Fluid

Hydraulic fracturing of gas shale reservoirs involves sequenced events requiring thousands 

of barrels of water‐based fracturing fluids mixed with proppant materials pumped in a controlled and monitored manner into target shale formations above fracture pressure24. Fracturing fluids used for fracturing gas shales include a variety of additive components, each 

with an engineered purpose to facilitate fractures and the production of gas25. Currently, the 

trends in shale wells are water based or mixed slickwater-fracturing fluids. These are water‐

based fluids mixed with friction reducing additives26, which allows a fracturing fluid and 

proppant to be pumped to the target zone at a higher rate and reduced pressure than by 

using water alone. In addition to friction reducers, other additives including biocides are utilized to prevent micro‐organism growth and to reduce bio‐fouling of fractures. Oxygen scavengers and other stabilizers which prevent corrosion of metal pipes and acids which are used 

to remove drilling mud damage near the wellbore area are also common either in fracturing 

fluids or as part of fracture treatments. 

An excellent review of the various components typically used during slickwater hydrofracturing is provided by D. Arthur et al of ALL Consulting25 and are reproduced in Figures 18 and 19. 

Some of the operators have also published information on their practices, most notably, 

Chesapeake Energy27. Fortuna Energy, a subsidiary of Talisman Inc., has provided details on 

the amounts of chemicals used, and their effective concentrations in the fracturing fluid, as 

shown in Figure 2028.

From the flowback water treatment perspective, although it is expected that some or all of 

these additives may be expected in the flowback, no literature reports confirming the presence and concentrations of these additives could be found. It is likely that these compounds 

may get chemically, physically or microbiologically altered or destroyed during the hydrofracturing process or become lost in the shale formation. Although some of these additives, such 

as guar gel, polyacrylamides, petroleum distillates may affect membrane performance; the 

actual impact would only have to be experimentally determined with flowback water samples. 
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Figure 67. Volumetric composition of a representative hydraulic fracturing fluid excluding the 

proppants (reproduced from D. Arthur et al., ALL Consulting25). 
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Figure 68. Additives in the hydrofracturing fluid 

(reproduced from D. Arthur et al, ALL Consulting3)
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Figure 69. Additives used in the hydrofracturing fluid, as reproduced from information published 

by Talisman Energy, Inc28
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5 References

 

1 Acharya, H.R., Moore, B., Wang, H., 2010. ―Cost effective recovery of Low TDS Frac Flowback Water for 

Reuse.‖ Ground Water Protection Council Conference, Pittsburgh, PA, September 27, 2010.

http://www.gwpc.org/meetings/forum/2010/proceedings/3Acharya_Haris.pdf

2 Acharya, H.R., Silva, J. M., Wilson, M. ―Shale Gas Frac Flowback Treatment.‖ Canada Society for Unconventional Gas, Water Workshop, Calgary, Canada, April 20, 2011. 

http://www.csug.ca/index.php?option=com_jevents&task=icalrepeat.detail&evid=165&Itemid=57&y

ear=2011&month=04&day=20&title=water-workshop&uid=ef6a76d3e36931dc9ae8f983582e44e3.

3 D. Arthur et al. ALL Consulting, Hydraulic Fracturing Considerations for Natural Gas Wells of the 

Fayetteville Shale, 2008 http://www.all-llc.com/publicdownloads/ALLFayettevilleFracFINAL.pdf

4 T. Gaudlip, Preliminary Assessment of Marcellus Water Reuse – Operations Manager Water Resources, Coldwater Conference, 20 February, 2010 

http://www.coldwaterheritage.org/KCC%20presentations/Gaudlip.pdf

5 Prof. D. Burnett, Texas A&M, DOE-NETL Oil Technology E&P Program, Environmental (Treatment Technology) Projects Kick-Off Meeting, NETL Morgantown, WV, January 12, 2010.

6 T. Langford, GE Water, Personal communications with well services operators.

7 Chesapeake Energy, Managing Water Resource Challenges in Select Natural Gas Shale Plays GWPC 

Annual Forum, September 20-24, 2008 

http://www.gwpc.org/meetings/forum/2008/proceedings/Ground%20Water%20&%20Energy/Satte

rfieldWaterEnergy.pdf

8 Chesapeake Energy Company website: 

http://www.chk.com/Media/CorpMediaKits/Water_Use_Fact_Sheet.pdf

9 Veil, J.A., Puder, M.G., Elcock, D., and Redweik, R.J., "A White Paper Describing Produced Water from 

Production of Crude Oil, Natural Gas, and Coal Bed Methane," ANL Report under DOE (NETL) Contract 

W-31-109-Eng-38 (2004).

10 Horn, A.D., Breakthrough Mobile Water Treatment Converts 75% of Fracturing Flowback Fluid to 

Fresh Water and Lowers CO2 Emissions, Society of Petroleum Engineers, SPE 121104, 2009

11 Mark Wilson and Todd Langford, GE Water, personal communications, March, 2010

12 Fact Sheet - Using Muds and Additives with Lower Environmental Impacts, DOE NETL website: 

http://web.ead.anl.gov/dwm/techdesc/lower/index.cfm

13 T. Hook, GE Water, Personal communications with well services operators, 2010.
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14 John A. Harper. The Marcellus Shale – An Old ―New‖ Gas Reservoir in Pennsylvania. In Pennsylvania 

Geology, Volume 28 Number 1. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources. 2008.

15 P. Kaufman, G.S. Penny, and J. Paktinat, Critical Evaluations of Additives Used in Shale Slickwater 

Fracs, SPE 119900, 2008 SPE Shale Gas Production Conference, Irving, Texas, U.S.A., 16-18 November 

2008.

16 T. Gaudlip, Preliminary Assessment of Marcellus Water Reuse – Operations Manager Water Resources, Coldwater Conference, 20 February, 2010 

http://www.coldwaterheritage.org/KCC%20presentations/Gaudlip.pdf

17 T. Langford, GE Water, Personal communications with well services operators.

18 M. Tate and D. Adams, Waste Water Treatment Requirements, Regulatory Analysis Review, Pennsylvania Department of Environmental Protection, Chap 95 Regulation, Independent Regulatory Review Commission, p. 355, May 2010.

19 M. Tate and D. Adams, Waste Water Treatment Requirements, Regulatory Analysis Review, Pennsylvania Department of Environmental Protection, Chap 95 Regulation, Independent Regulatory Review Commission, p. 7, May 2010.

20 GE Winflows membrane system design software available at: http://www.gewater.com/winflows.jsp

21 GE Water website on softening methods for industrial wastewaters: 

http://www.gewater.com/handbook/ext_treatment/ch_7_precipitation.jsp#

22 GE‘s Mobile Evaporator for treatment of frac flowback water. 

http://www.geunconventionalgas.com/mobile-evaporators.html

23 Fact Sheet - Using Muds and Additives with Lower Environmental Impacts, DOE NETL website: 

http://web.ead.anl.gov/dwm/techdesc/lower/index.cfm

24 Schlumberger Fracturing Services Page of Schlumberger website, www.slb.com September 2, 2008. 

25D. Arthur et al. ALL Consulting, Hydraulic Fracturing Considerations for Natural Gas Wells of the 

Fayetteville Shale, 2008 

26 John A. Harper. The Marcellus Shale – An Old ―New‖ Gas Reservoir in Pennsylvania. In Pennsylvania 

Geology, Volume 28 Number 1. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources. 2008.

27 Chesapeake Energy Company website: 

http://www.chk.com/Media/CorpMediaKits/Water_Use_Fact_Sheet.pdf
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28 Talisman Energy (Fortuna Energy), 

http://www.talismanusa.com/upload/media_element/26/01/microsoft-word---chemicaldescriptions-for-marcellus-shale-wells-fortuna-_2_.pdf