# Cost Effective Recovery of Low

- TDS Frac Flowback Water for Re

- use Department of Energy: DE

- FE0000784

Final Report Reporting Period: October 1, 20 09

– 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, W V2
GE Global Research



## 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 comme rcial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its e ndorsement, 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 r eflect 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 env ironmental impact of sha le gas production. This effort sought to develop both a flowback water pre

treatment 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 hydr ofracturing oper ations. 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 pr oduction 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 di scharge applications. Pretreatment technologies were evaluated at the lab scale and down

- selected based upon their efficacy in re moving key contaminants. The chosen technologies were further val idated by performing membrane fouling studies with treated flowback water to demonstrate the tec hnical feasibility of flowback treatment with RO membranes. Process flow schemes were construct ed 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 mode ling software was used to create designs for enhanced water reco very 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 attra ctiveness of a given flowback recovery process relative to conventional dispo sal for any combination of anticipated flowback TDS and local disposal cost. It is concluded that membrane systems in combin ation with appropriate pretreatment technologies can provide cost

- effective recovery of low

- TDS flo wback water for either beneficial reuse or safe surface discharge.3
GE Global Research



## 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 collab oration 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 se tting 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

- vis i ts and conta cts 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 Vascon celes, John Piechel, Peter Ericksson, Tom Ciarra, and I rving Elyanow for their recommendations of water pretreatment and membrane systems, d esign and costing information, and the many reviews with very valuable feedback.4
GE Global Research 

## 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 appro ach

................................ ................................ ................................ .......... 58 3.4.3 Process Step: ―Clarify‖

................................ ................................ ................................ ................................ ....... 59 3.4.3.1 Removal of Organics

................................ ................................ ................................ ................................ ......... 615
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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 Energy 7 )

................................ ................................ ................................ ................................ .. 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 obtai ned 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.

.......... 1 4 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 decision s.

................................ ................................ .............................. 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 (Gaudlip 4 ).

................................ 25 Figure 7. Flowback rate vs. time for a Woodford shale (re

- plotted from the data shown in Horn 10 ).

....... 25 Figure 8. Flowrate profiles for frac flowback from three Woodf ord shales.

................................ ........................... 26 Figure 9. Composition of a flowback sample from a Marcellus shale site (reproduced from Gaudlip 4 ).

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GE Global Research

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 Sol ids (TDS) concentration profiles for flowback waters from a few Woodford shale wells

................................ ................................ ................................ ................................ ................................ ...................... 29 Figure 13. Photograph shows a salin e 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 Carbo n for the two Woodford frac sites.

................................ ................................ ................................ ................................ ................................ .. 35 Figure 18. Concentration profiles for Total Hardness and Alkalinity for the two Woodford fra c 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 Company 4

. ................................ ... 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 contaminant s 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 f rac flowback waters. Results of bench

- scale experiments with the ―composite‖ Days 1

- 14 Woodford Site

- 1 sample.

................................ ................................ ................................ ..... 59 Figure 36. Clar ification 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. C larification 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.

................................ .. 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.

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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 eioson oate).

.... 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 bench

scale 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 software 20

. ................................ ................................ ................................ .... 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‖ spira l wound RO module runs using 10~15 liters of pretreated field frac flowback samples. See text for details.

................................ ................................ ....... 76 Figure 54. Salt

- r ejection 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: C Recovery , C Conc_disposal and C FWRP for the operating and cost parameters developed in this project and for an assumed value of C Disposal

. .. 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 p pm TDS retentate from the membrane unit is distilled in the mobile evaporator to yield a 280,000 ppm TDS concentrate.

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Figure 6 5. 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 C FWRP /C Conventional 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 Consulting 25 )

. ................................ ................................ ....... 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, Inc 28

................................ ................................ ................................ ................................ .............................. 979
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## List of Acronyms
Acronym Definition b bl Barrel (1 bbl = 42 gallons) Conventional Conventional Flowback Water Disposal Process based on Class II SWD C Chemicals Cost of process chemicals, $/bbl flowback C Conventional Cost of Conventional Flowback Water Disposal Process, $ C Disposal Cost of flowback disposal (= C Transport + C SWD ), $/bbl C FWRP Cost of Flowback Water Recovery Process, $ C Fresh Water Cost of fresh water for frac use, $/bbl C M aintenance Cost of annual maintenance per annual feed processed, $/bbl flowback C Penalty_Avoid Value of penalty avoided due to flowback re

- use C Process Cost of process steps (capital and operating expenses), $/bbl feed C Product Delivery Cost of product d elivery to re

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

- use, $/bbl product C Recovery Cost of product recovery (= C Treatment + C Product Delivery – C Product_Value +C Penalty_Avoid ),

$/bbl product C SWD Cost of salin e water disposal by deep well injection, $/bbl C Setup Cost of mobile rig transportation and setup at the frac site, $/bbl feed C Treatment Cost of flowback treatment to produce product (=C Setup + C Process ) , $/bbl feed C Transport Cost of transportation o f disposal water, $/bbl flowback or concentrate C Waste Cost of FWRP process waste disposal, $/bbl flowback ―Cut

- off‖ TDS The value of yF where the C FWRP / C Conventional = 1 repre sents 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 X P retreatment Extent of fl owback recovered after pretreat ment prior to membrane desalin ation), bbl/bbl flowback y F Feed TDS concentration, ppm y Concentrate Concentrate (sent to SWD) TDS concentration, ppm y Distillate Distillate (from thermal evaporator) TDS concentration, ppm y Permeate Permeate (from membrane) TDS concentration, ppm y Product Product TDS concentration, ppm y Retentate Membrane retentate (reject) TDS concentration, ppm10
GE Global Research



## 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 th e reporting period

, beginning October 1, 2009 an d ending March 30, 2011. The project goal was to develop a cost

- effective water recovery process to reduce the costs and env ironmental impact of shale gas production. This effort sought to develop both a flowback water pre

treatment process and a membra ne

- based partial demineralization process for the treatment of the low

- Total Dissolved Solids (TDS) portion of the flowback water produced during hydrofracturing oper ations. The TDS cutoff for consideration in this project is < 35,000 ~ 45,000 ppm, which i s 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 methodol ogies 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 im portant 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 review ed info rmation published in open lit erature and obtain ed 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 purif ication:

 Product

- 1: Clarified only (removal of suspended matter, free oil & grease , Fe, and microbiolo gical 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 deter mined to be :

 Product quality specifications for the Products 1

- 4 to their respective target applications. W ater 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 C osts (mobil e rig related process equipment

, transportation & setup

, chemicals and waste disposal , power ) and Concentrate D isposal C osts. For the shale plays under consideration, th is translates to target Treatment C ost < $2/bbl flowback water

.11
GE Global Research  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 proper ties 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 fractu ring operations. Moreover, flowback volume and water properties vary thro ughout the lifetime of the well. The components in the flowback water of interest in this project are particulates (>5 μm), su spended solids (<5μm, colloids), free oil, dissolved organics, volatile organics, hardness ions (Ca, Mg, Ba, Sr, sulfates, carbon ates), Fe, silica, and bacteria that may affect the product quality and/or the desal ination 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 pr esent 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 day s, ~30

- 40% of the flowback may qual ify 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 l ow

- TDS recovery. However, 10

– 2 0% of the flowback may be amenable at certain loc ations 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

- 1 4, 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 flo wback from another nearby well. These water samples were used in experiments for assessing pr etreatment and membran e 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 specific ations for the altern ative 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 components12
GE Global Research

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 me mbrane desalination , key membrane foulants, namely ino rganic 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 the se bench

- scale experiments. For demonstration, RO membrane fouling experiments were conducted using commercially available 2‖ diameter spiral wound RO modules with 10 liters of pr etreated 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 fou lants.

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 solut ion composition similar to that obtained after pretreating (lime softened and filtered) Site

- 2 Day

26 sample, the identified configurations increased the recovery from 49% for a standard seawater

desalination design to as high as 61.5%. The maximum retent ate concentration correspondingly i ncreased from 68K ppm to 90K ppm TDS for these conditions. The increase in capital costs due to add itional pumps, membrane modules, interconnected piping and controls for the new configuration were more than offset by th e 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 co nstructed for each of the Products 1

- 4 u nder 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, includ ing 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 co st 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 suit able to treat 50 gpm of the frac flowback water.

The Treatment C ost target of <$2/bbl was satisfied for all product options , in line with preliminary feed back on customer expectations. For the 50

- gpm mobile rig configuration, the ―fixed‖ expenses (capital

- related costs, rig transportation & setup, mainte nance) dominated the Treatment C osts at ~75% followed by chemicals & solids waste disposal at 18%, while the cost s of replacement me mbranes and electrical power were only 2% and 5%, respectively

A value

- ass essment cost model was developed for the overall FWRP for the Products

- 3 &

- 4 that use RO membrane desalination to compare with the c onventional disposal method

. T he c onventional di sposal cost included transportation of all flowback water and injection in Class II SWD wells while the FWR P cost included treatment costs , product delivery and remaining concentrate disposal (transport + SWD injection) costs. T he sensitiv ities of the FWRP cost to prevailing concentrate disposal condi tions were expressed as pl ots of C FWRP /C Conventional vs. C Disposal at different feed TDS concentrations. The ec o-13
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nomical ―cut

- off‖ TDS is defined as that feed TDS concentration when C FWRP /C Conventional =1

. For Product

4 (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 treat ment opportunity based on prevailing disposal costs and anti cipated 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 case s, these

non

- technical issues may be the economic driver for FWRP.

To increase the ov erall system water recovery, a H ybrid membrane + thermal system was also consi dered. In this approach, the retentate (90,000 ppm TDS) from the membrane system is further conce ntrated by distillation in a mobile evaporator (such as that introduced by GE Water recently 22 ) to yield a distillate with <500 ppm TDS but mo re importantly, a concentrate with 280,000 ppm TDS. The H ybrid system yields higher recovery ; f or example, 85% for a feed with yF = 35,000 ppm TDS vs. 61% for the membrane rig alone. However, the H ybrid 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 C FWRP /C Conventional vs. C Disposal at different feed TDS concentrations show the dramatic decrea se in C FWRP for the Hybrid due to increased water recovery. The Membrane alone case is more economical for the lower C Disposal cases mainly due to the lower overall capital costs . However, the Hybrid case becomes more economically attractive for the high C Disposal (>$5/bbl) shale plays where local SWD sites are un available

, thus leading to higher flowback water transportation costs for the conventional disposal method

. It is concluded that membrane systems in combination with appropriate pretreatment te chnologies can provide cost

- effective recovery of low

- TDS frac flowback water for either beneficial reuse in hydr ofracturing or safe surface discharge.14
GE Global Research



## 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 r educes the cost of treating flowback water for re

- use in the hydrofracturing process.
The principal goal of this project wa s to define a mobile, cost

- effective membrane

- based process to treat low

- TDS frac flowback water for re

- use as hy drofracturing fluid. The TDS cutoff for considerati on 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 pr ocesses. 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 separ ator 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, typical ly 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 w ater for re

- use in hydrofracturing operations is shown in Figure 2. The flowback water reco very 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 oper ations 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.15
GE Global Research

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 recover y by methods suitable for desa lination of high

- TDS waters (> 8 0,000ppm), such as thermal pr ocesses.

The o verall 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 water

transportation related traffic on roads, reduced water disposal costs, and a greatly reduced impa ct on the environment.



## 2 Budget Figure 2

. Conceptual Flowback Water Recovery Process (FWRP) for re

- use in hydrofracturing.16
GE Global Research

Total funding for this program was approximately $ 1 MM including a 20% cost share contri buted 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 under

spent by $ 65K at the end of March 2011 . However, final report a nd report

- out is anticipated to bring this num ber 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 specification s 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 interrela tionship chart summarizing the logic that connects the various tasks are shown in Figure 3 and Figure 4

.17
GE Global Research

Figure 3

. Schedule and milestones for the program.18
GE Global Research Figure 4 . Task interrelationships and Go/No

- go decisions.19
GE Global Research



## 3 Results a nd 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 pr oposed 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 te am presented work done for the project at the 2010 Ground Water Prote ction Council Annual Meeting, Pittsburgh, PA, Sep 26

- 28 1 and the Canadian Society of Unco nventional Gas Water Workshop, April 20, 2011 2 . Additionally, presentations were made to potentia l customers to educate and highlight potential solutions to frac flowback and pr oduced 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 :

 Und erstand frac flowback operations and estimate the amount of flowback that qua l ifies as ―low

- TDS‖ water suitable for recovery via membrane processes

 Define performance and cost specifications, and develop the verification of success criteria for assessing t he 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 informatio n published in open literature, discussed w ith frac operators, and vi sited a frac flowback site to get a better understanding of the actual operation logistics. There have been several barriers to obtaining reliable information on t he water chemistry used for hydrofracturing, flowback attributes, and specifications for the re

- use water, inclu ding:

 The water chemistry used for hydrofracturing depends on the geology of the shale formation and the technology bias/experience of the opera tor. 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 bei ng continuously u pdated as the industry tries to optimize operations to maximize gas recovery while minimizing energy and especially, fresh water usage 3 . For example, current research20
GE Global Research 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. Ther e 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

s caling issues in the downhole piping , w hile others , such as Range Resources, have reported some success in using a 26,000 ppm Chlorides water feed in the Marcellus shale 4 . Some experts feel that water salinity equivalent to seawater, namely ~ 35,000 ppm T DS may be usable for hydrofracturing 5 . Some operators are considering the use of even salinity as high as 120,000 ppm TDS with low hardness and scale

- causing contaminants 6

. As a practical matter, the relative costs for drilling and hydrofractu ring 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, i t appears that the move towards higher TDS water used to stimulate gas wells is being driven by state and regional water avail ability , 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 di sclosure of chemistry used for the hydrofracturing process, discharge of flow back w ater, and the re

- use of flowback water for hydrofracturing. Until the regulations are f inalized, there will be uncertainty on the specifications for the treated water and di scharge water. This affects the determination of how much of the flowback w ater would qualify as ―low

- TDS‖ suitable for membrane treatment, the choices of techno logy options useful to treat the frac flowback water to meet the technical specific ations, and the overall system cost.
The conclusion fr om our survey wa s that the specif ication for acceptable re

- use is subject to change in the short

- term depending on technology advances that are continuously occu rring, operator experience and confidence, and upcoming regulations regarding discharge and re

- use. Nevertheless, we were able t o find relevant information on the flowback and produced w aters in the Marcellus, Haynesville, Barnett, Fayetteville and Woodford shales. Some of this d ata was acquired under non

- disclosure agreements and will only be summarized as appropr iate in the follo wing sections.21
GE Global Research

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 su rface, 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 sma ll cracks in the rock and allow gas to freely flow to the surface. Typical average usage of water for drilling and frac operatio ns for the Barnett, Fayetteville, Haynesville and Marcellus shales, as estimated by Chesapeake Energy Company 7 are shown in Table 1.

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

es timated by Chesapeake Energy 7 )

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 hydr ofracturing 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 conve ntional oil & natural gas fields and in coal bed methane reservoirs, there is an ex cess 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 estima ted that approximately 7 bbls of water are produced for every bbl of oil 9 . 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 Horn 10 , when the flowback volume reaches 100% of the fracturing fluid volu me, it is then subsequently referred to as ―produced water‖. However, our survey 11 of gas pr o22
GE Global Research

ducers appears to indicate that the rationale for referring to the water as ―flowback‖ or ―pr oduced‖ could be any of the following:

1. Financial: Water produced du ring 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 a ssociated costs are part of the "opera ting" 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 signif icantly during this period.

3. Volume: Some producers differentiate based on how mu ch they get back as a pe rcent of fracturing fluid put down into the well. It may be 100% as per the definition provided by Horn 10 or less, as per the operator‘s choice. However, in shale gas wells, the overall water flow back could be < 50% of the fracturing fluid used, typically only 25

- 35% in the first 30 days.
It app ears that the financial reason appears to be the most commonly used definition to di fferentiate between ―flowback‖ and ―produced‖ waters. In any case, for shale gas wells, from a flow rate perspective, the flow rates during the ―flo wback‖ phase are signif icantly larger (by 10

- 100x) than in the ―produced‖ phase. From a che m ical 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 hydr ofracturing operations . However, for some shales, the chemical characteristics during the flowback phase may have already approached those at the produced phase of the opera tion (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 o ptions.

3.2.4 Wa ter 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 fr om 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 the23
GE Global Research

DOE NETL website 12 . Relevant information for this project is summarized in Appendix A

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

 ―oil‖ in the oil

- ba sed 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 l ocations, after drilling, the equipment are cleaned with diesel, although this practice may be disconti nued in the future 13

.

 olefins, esters, linear alpha

- olefins, poly alpha

- olefins, linear paraffins, etc. in the sy nthetic

- based muds, if used.

Frac fluids: Fracturing fluids used for fracturing gas shales include a variety of additive components, each with a n engineered purpose to facilitate fractures and the production of gas 3 (see A ppendix for details). Currently, the trends in shale wells are to use water based or mixed slic kwater

- fracturing fluids. These are water‐based fluids mixed with friction reducing additives 14

, which allows a fracturing fluid and proppant to be pumped to the target zone at a higher rate and reduced pressure than by using w ater alone. In addition, other additives including bi ocides 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 h ydrogen 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 st abilizers 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, alt hough it is expected that some or all of these additives may be expected in the flowback, no literature reports confirming the pre sence 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 hydrofra cturing 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 the ir data proprietary and confidential. There is very limited published data on the flowback attributes for the various shales. Neve rtheless, we were able to find relevant information on the flowback & produced water attri butes for the Marcellus, Haynesvil le, Barnett, Fayetteville and Woodford shales. Most of this24
GE Global Research

data was acquired under non

- disclosure agreements and will only be summarized, as appr opriate in the following sections.

Flowback Flow rates For the Marcellus shale, Gaudlip 4 has reported flowback volumes over a period of 14 days for a few wells, as reproduced in Figure 5

.

Figure 5 . Flow back 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 days 11

.

 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 signi ficant 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 betwee n 5 to 100 bbl/day but mostly ~ 10 bbl/day (or 0.4 bbl/hr).25
GE Global Research

Figure 6 Flow rates vs. Flowback time for a few wells in the Marcellus shale (Gaudlip 4 ). Blue points refer to ―Flowback‖ and the red points refer to ―Produced‖.

Horn 10 has reported flowback attributes for a Woodford shale site. Their flow rate data is re

plotted in Figure 7 . We again observe that the flow rate was ~ 150 bbl/hr for the first 3 days and the n 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 Woo dford shale (re

- plotted from the data shown in Horn 10 ).26
GE Global Research

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 Gaudlip 4 . The composition of a flowback sam ple from a Marcellus shale site is reproduced in Figure 9.

Figure 9 . Composition of a flowback sample from a Marcellus shale site (reproduced from Gau dlip 4 ). Figure 8 . Flowrate profiles for frac flowback from three Woodford shales.27
GE Global Research

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 c hlorides c oncentration at ~97K ppm make up ~60.6wt% of the TDS. Interestin gly, 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, M Cl /M NaCl =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 b asis)/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 p otassium is perhaps from KCl added to the fracturing fluid during h ydrofracturing. 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 fo rm 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 Fe 2+ state, which may potentially get oxidized and form undesired precipitates that could

cause scaling. Gaudlip 4 has also reported on the variation of chloride concentration in the flowback as a function of flowback time, as reproduced in Fig ure 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 value s 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 TD S in flowback) may have limited applications in the Marcellus shale play. However, we o bserve from composition data obtained from elsewhere in the Marcellus shale play from co n-28
GE Global Research

fidential sources, that 10

- 2 0% of the flowback may be amenable at certain locat ions 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 al 15 have described the flowback composition. The data for the sulfates and Ba / Sr compositions plotted as a function of the cumulative flo wback volume are reproduced in Figure 11 . We observe a sharp transition at ~ 11,000 bbls when the Ba/Sr c oncentrations increase to cause a precipitous drop in Sulfate concentr ations.

Figure 11 . Variation of Sulfates and Ba/Sr concentrations as a function of flowback volume for a Haynesville shale29
GE Global Research

For the Woodford shale, Total Dissolved Solid s (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 chemi cal properties of flowback water vary considerably depending on the g eographic location of the shale play, the geological formation, and the chemicals introduced during the drilling and fracturing operations. Flowback volume and water properties vary thro ughout 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 ec ono m ic recovery using RO

- based membrane recovery systems. The initial flowback typ ically 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. T he average values represent a combined mean for flowback from a well w hile the maximum could be an instantaneous value. Note that the a ctual values will vary widely from the nu mbers 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 wells30
GE Global Research

Table 2 . Salinity of the flowback waters from various sh ales 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 di recting 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

ava ilability 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

- 2 0% of the flowback may be amenable at certain locations with appropriate water ma nagement 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, th e re is li mited 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 o perator 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 flo wback 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.31
GE Global Research

3.2.9 Frac site visit We visited a frac site in the Barn ett shale in Fort Worth, TX area to get a first

- hand unde rstanding of the flowback operations and the water

- handling logistics. Due to safety co ncerns, we could not visit this site during the hydrofracturing process b ut our visit happened immediately afte r the ―frac

- job‖ and while the well services crew was managing the flo wback. 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 hydr ofractured wells producing gas. At this site, the saline water was being disposed into the E llenburger formation that was below the shale

- gas formation layer. One of the remarkable impressions of these site visits was the general cleanliness of the opera tional 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

- Mar ch, 2010. For client confidentiality reasons, the cu stomer 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 flowba ck.

o Daily 1

- liter samples were collected from Day

- 1 through Day

- 1 4

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 r eferred to as ―Site

- 1 Composite‖ samp le. Figure 13 . Photograph shows a saline water disposal (SWD) well co

- located with three hydrofractured wells producing gas.32
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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 component s/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

- 1 2, the flowrate appears to decrease with time. Interestingly, the flowrate profile at t his 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 15 0°F. T he flowback water temperature varies across frac sites and with time. Water from deeper wells tend s to have higher temperatures. Also, the temperature is higher initially when the flowback rates are highest and gradually d ecreases 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; alternative ly, Figure 14 . Profiles of the flowback water rate and water temperature are plotted vs. flo wback time for the Site

- 1 in Woodford shale.33
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we may need to install adequate heat exchange equipment if the chosen treatment proces ses 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 stan dard 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

- 2 3.
Total Dissolved Solids (TDS) The TDS values for Woodford Sites 1 and 2 are pl otted in Figure 1 5. 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

- 1 4. This is in contrast to all the other data we had seen from customers in the Woodford s hale, wherein the general trend showed that the TDS after Day

1 4 was between 10,000 and 38,000 ppm , as seen in Figure 12 . Interestingly, the Day

- 26 sa mple from Site

- 2 had ~35,000 ppm TDS, which is in agreement with the general trend. Horn 10 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 w ater sample through a 1.0 micron filter and weighing the residue material after drying . Tu rbid i ty , measured and reported in NTU units, refer s to the transmission (or lack of) of light Figure 15 . Concentration profiles for Total Dissolved Solids (TDS) for the two Woodford frac sites.34
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through a water samples. Turbidity may be influenced by the suspended solids and also co lor of the sample. In Figure 1 6, 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 flow back 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 f or the two Woo dford frac sites. Organics: The organic content of the flowback waters w as 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 co mbustible 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 rep orted here.35
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The profiles for the Hexane Extractables and TOC for the fl owback waters for the Woodford S ites 1 & 2 are plotted in Figure 1 7. For the Site

- 1 flowback over Days 1

- 14, we observe high initial values for Hexane Extractables followed by a shar p decrease over the next few days. The values are below detection beyond Day

- 1 0 for Site

- 1 which also corresponds to neglig ible value for the Day

- 26 sample from Site

- 2 . The TOC profile for the Site

- 1 Days 1

- 14 sa mples also show s 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 thro ugh 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 chem icals present immediately after a frac operation, while the data for the subsequent flowback may be reflective o f 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 a nd carbonates, need to be measured & monitored. The Total Hardness estimated from the concentrations of the individual potential scale

forming ions and reported in terms of ppm CaCO3 is shown in Figure 18. We observe that for the Site

- 1 Days 1

- 14 flowb ack, the values climb from an initial ~ 4,000 mg/l CaCO3 to ~36
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14,000 mg/l CaCO3 by Day

- 1 4. By contrast, the Day

- 26 sample from Site

- 2 shows a signif icantly 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. Horn 10 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 si tes.

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.37
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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 va lue decreases to ~ 95% for l ater 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. 60 8 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 wa s 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 fo r the two Woodford frac sites.38
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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 s olubility, 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 2 1. We also observe that the Ba conce ntrations increase from ~3 p pm i nitially to ~ 68 ppm on Day

- 14 for the Site

- 1 Days 1

- 14 flo wback while the Site

- 2 Day

- 26 flowback sample has only ~ 30 mg/l. Horn 10 has reported a va lue 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

- 1 4 for the Site

- 1 Days 1

- 14 flowback while the Site

- 2 Day

- 26 flowback s ample has only ~ 174 mg/l. The Sulfate concentrations decrease from ~ 100 mg/l initially to below detection beyond Day

1 0 for the Site

- 1 Days 1

- 14 flowback, while the Site

- 2 Day

- 26 flowback sample has negligible concentration. Iron, Manganese and Boron :

F e 2+ is a concern as it may oxidize to form Fe 3+ , which may readily form precipitates with va rious anions. Similarly

, Mn may oxidize to form precipitates. The concentration profiles for Fe, Mn and B are plotted in Figure 2 2 for the two Woodford frac si tes.39
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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

- 1 4. The Site

- 2 Day

- 26 flowback water contains ~ 72 mg/l Fe. This is imp ortant 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

- 1 4, 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 la tter is of concern as a potential foulant for desa lination membranes. In Figure 2 3, the conce ntration 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 measu rements of silica for the Site

- 1 Days 1

- 14 flowback with the values be tween 20 and 70 mg/l: the silica conce ntration 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 reac tive silica by Day

- 14. The Site

- 2 Day

- 26 flowback water contains ~ 120 mg/l total silica and ~60 mg/l reactive sil i-40
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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 R eactive 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 specif ically 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 r esults 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 obt ained 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 stu dies in Task 4 and 5. Although the TDS values of the wa ter samples obtained from Site

- 1 were too high for the consideration of RO

- type membrane p rocesses for desalination, the samples

were useful for the bench

- mark evaluation of pretreatment processes for the removal of ot her undesired components in Task 4

.41
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Table 3 . Compositions of the three 55

- gal drums obtained from the W oodford shale that were used for bench

- mark testing in Tasks 4 and 5.

Figure 24 . Photographs of vials containing frac flowback s amples from Woodford shale Site

- 1 Days1

- 14 and Site

- 2 Day

- 26

.42
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3.2.11 Specif ications 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 opera tion at a shale gas well site.

3.2.11.2 Conventional water disposal Flowback water may be dispos ed 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 di sposal sites are available locally and the cost of disposal is relatively cheap at $1

- $3/bbl. However, such deep well injection sites a re few in the Marcellus shale (West Virginia, Pennsylvania, New York), and hence t here is a need to transport the flo wback 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 independ ent operator in the PA area ind icated 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 well 3 . For the Woodford shale (Oklahoma), the trucking costs are e stimated at $3.71/bb l and disposal between $1

- 2/bb l 10

.
 Surface water discharge: Until recently, this mode of disposal was used in the Ma rce l lus shale in the PA area. PA DEP 25 regulations enacted in August 2010 limit su rface 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 , b ut there are restrictions to such use 3 . 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 appli cation permits, it must have a chloride concentration of43
GE Global Research 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 ut ilized on roads for dust suppr ession. If chloride concentrations exceed 5,000 ppm, di sposal 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 hydrofra cturing operations is shown i n Figure 2 6 . The flowback water recovery process (FWRP) is pre ferably located physically close to the well operations to minimize water hauling costs. It i ncludes a mobile unit equipped with the necessary treatment operations to provide a ―pro duct‖ water that meets specifications for re

- use in hydrofracturing. Only a portion of the flo wback 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 me thods 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 27.44
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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 shale 16 . In fact, Range R esources and Chesa peake report ed 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 w ater s alinity equivalent to seawater, namely ~ 35,000 ppm TDS may be usable for hydrofra ctu r ing 5 . 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 contaminants 17 , but we co nsider 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 a nti c ipated before frac use.
To develop specifications for frac re

- use water, we evaluated the limited information avail able in literature and spoke to frac operators. The data provided by Range Resources 4 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 repor ted characteristics, which was successfully used for hydrofracturing at another site.45
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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 Company 4

. 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 developed 18 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, calc ium, iron, manganese, and strontium Moreover, the methods used for hydrofracturing are being continuously updated as the i ndustry 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 b eing considered by various state and federal ag encies 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 u ncertainty on the specifica tions for the treated water and discharge water. This affects the determination of how much of the flowback water would be treatable, the choices of tec hnology 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 p r oposed to potentially four alternative products with varying levels of purification:46
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1. Product

- 1 : Clarified only (removal of suspended matter, free oil & grease, Fe, and m icrobiological 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 Pro duct

- 2).
These product options and the associated target contaminants for removal are shown in Figure 29.

Figure 29 . . Product Options for frac flowback water recovery. The target contaminants a re listed for each process step in the respective boxes. The target contaminants to be removed in each pr ocess 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 su itable for re

use 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 contamin ants 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 desal ination membranes that would be used to produce Product

- 3 and Product

- 4.4 7
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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 compositio ns of the frac fluid before and a fter additives blending for a conventional ―fresh‖ water source. Also

, t he specifications for Product

- 3 appear to be roughly half of the Chlorides and TDS reported by Range Resources in Figure 2 8

. We felt that it was pru dent 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 d epending on the efficiency of the sludge handling methods employed.

Ho wever, t he 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 are a available. As water permeates through the selective membrane inside the permeator module, the conce ntration of salts and other non

- permeable components, such as silica, organics, etc.

, increase in the retentate. This results in the need for a greater p ressure 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 desalin ation, 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 29.48
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ppm

– the actual value will depend on the concentrations of the other ions, silica and other components.

I n Figure 31 , the extent of recovery, x

, is plotted as a function of the flowback TDS concentr ation 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 l ow

- TDS product that is suitable for potable water or surface discharge (Product

- 4), and t he 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 desalina tion to produce potable water (<250 ppm TDS) is also shown in Figure 31.

Figure 31 . Plot of extent of product recovery, x as a function of the flowback water concentration and desired permeate prod uct water concentrations when retentate concentration is limited to 70,000 ppm TDS. The applicable range of flowback water composition for ―Low

- TDS‖ recovery process es is e xpected 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 (500 ppm 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 sp ecifics of the shale site. The factors to consider are (a) the salinity and other contaminants in the flo wback water that would limit the recovery (x), (b) the cost of conventional disposal options, (c)49
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any regulations (penalties) related to disposal of t he flowback waters or use (ben efits/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 ―chea pest‖ process that meets the technical specifications at the ―highest‖ r ecovery. 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 ot her recovery method (e.g. thermal recovery) including transportation.

These are represented below:



### C FWRP 

### = C Recovery 

### + C Concentrate disposal 

### ($/bbl feed ) (1)

C Recovery 

### = C Treatment 

### + C Product D elivery 

### - (C Fresh Water 

### + C Penalties _Avoid 

### ) ($/bbl product) ( 2 )

w here t he cost for the product recovery C Recovery include s 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 avoi dance of penalties from exist ing or pending regulations.

T he 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

, C Penalties _Avoid is unknown at the moment. Hence, although inclusion of C Fresh Water and C Penalties _Avoid offers a more economically attractive condition, a more conservative approach would be to ig nore them, as in eqn. (3 ): C Recovery  C Treatment + C Product_D elivery ($/bbl product) ( 3 )

The cost of delivery, C Product_D elivery will again vary depending on the distance between the re

use 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 expensive50
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option will be trucking over long distances. A reasonable estimate would be C Product_Delivery < $0.1 ~0.5 /bbl.

For the Flowback Water Recovery Process to be economically attractive, the minimum r equirement is:

C FWRP < C Conventional Disposal
From our earlier discu ssions, we noted that the typical conventional disposal costs

, including transportation, could vary depending on the individual shale plays and the availability of di sposal 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 Fayetteville 3 and $3.71/bbl for transportation and ~$1

- 2/bbl for disposal in Woodford 10 . (Although, interestingly, during the Pennsylvania Chap 95 regul ation analysis review, it was reported that even at costs anticipated for proper treatment a nd disposal at as high as ~$10/bbl, the annual costs would comprise a mere 0.4% of the est imated annual revenue 19 .).
From these values and feedback from a few well operators

, as well as paring down the co ntributions of product handling & delivery costs an d rig operating labor, the treatment cost criterion for this project was set as :
C Treatment < $2/bbl feed

Where C Treatment = C Setup + C Process
C Setup : Cost of mobile rig transportation and setup at the frac site

. C Process : 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 concentrate

dis posal. T he labor costs associated with setting up the mobile rig are included in C Setup and thus in the C Treatment 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 32.51
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Figure 32 . Verification of success criteria for the Low

- TDS frac flowback recovery process52
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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, w e, at GEGR, worked closely with various groups within GE Water & Process Technologies (GEWPT) to leverage their knowledge in treating various indu strial waste waters. Specifically, GEWPT Water Chemicals division offers a wide product por tfolio of chemic als used for membrane

- water pretreatment and corrosion prevention, GEWPT Membranes division offers a wide product portfolio on microfiltration, ultrafiltration, nanofi ltration, reverse osmosis, and membrane bioreactors for treating various municipal and i ndustrial 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

.53
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Figure 33 . Conceptual representation of a frac flowback recovery process to treat the frac flo wback 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 Pr etreatment

- 1 box in Figure 33

. The key contaminants to be removed are suspended solids, free oil & grease, bacteria, colloidal organic and inorganic material. Di ssolved 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 ste ps for disposal.
For Product

- 2, the output from Pretreatment

- 1 may be further treated to remove hardness

causing ions, mainly divalent and trivalent ions, in the step shown as Pretreatment

- 2 in Fi gure 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 genera ted w hen 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 exten t of water r ecovery is definitely higher for the solids

- precipitation method but it requires handling of so lids.54
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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 select ively exclude the permeation of mon ovalent 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 n anofiltration (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 membr ane area and lowest operating pressure ( ~100 psig range )

, while the high

- selectivity RO membranes typically have the lowest flux and would require the lar gest 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 c oncentrate stream from the m embrane 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 contaminan ts in frac flowback of concern for reuse The contaminants in the frac flowback water were discussed in Section 3.2.10.3 and the ir i mpact on water reuse for hydrofracturing wer e illustrated in Figure 27

. The salient aspects of these contaminants for evalua ting process technology options for cleanup are described b elow:

 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 ope rations. 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, metall ic or organic mat erials. 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 co uld be significant variability in the values during the flowback.55
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 Dissolved Organics: These could be small amounts of low molecular weight hydr ocarbons, polymers used as friction reducers (see Appendix ), or other organics from the formation. Reported val ues range from 10

– 150 ppm.

 Volatile Organics: Some of the dissolved and undissolved organics could be consi dered as volatile under normal operating conditions and as such may present co ncerns with emissions or fire/explosion hazards if the concentration s are too high. Condensates present in the shale gas that contaminate the flowback water, especia lly benzene, toluene and xylenes

, need to be explored as they are of public concern. Most literature values indicate <10 ppm for such compounds.

 Hardness: Th ese 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 ++ concentr ation 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 var iation as one travels from WV via PA to NY.

 Strontium: Reported values range from <50 ppm in Woodford to >2,000 ppm in Ma rcellus.

 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 r eactive silica; the latter is of concern as a potential foulant for desalination me mbranes.



###  N ORM: 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 concer ns 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

- effect ive?56
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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, ove rall 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, pol ya m ide membranes typically used for desalination will get fouled at high concentr ations 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 fo ulants or add anti

- scaling agents.

 Red: The technology option has some substantial risks that need to be retired by e ither pretreatment or post

- treatment.

The results of the analysis are shown in Figure 34

. The conclusions from the analyses are di scussed in the next section.57
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Figure 34 . Technology options evaluated in the preliminary screening in Task 3 for removal of the various contaminants in frac flowba ck water

. 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 an d the integrated process in a mobile rig.58
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### 3.4 Task 4: Evaluate key Pretreatment and Membrane Processes in bench

scale 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 r emoval 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 co ncentration and the desired product concentrat ions for the Product o ptions 1

- 4 described in Figure 30 . The various mechanical, chemical and membrane technologies that were ident ified to be  ̳Green‘ in Task 3 were evaluated via bench

- scale laboratory experiments. The e xperiments were conducted initiall y 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 add itives, such as coag ulants, flocculants, softening chemicals, sorbents, etc., various operating conditions, such as pH, concentrations, mixing times, settling times, temperatures, flow rates, etc. various sep aration equipment, such as filters, mixed

- media deep filtration beds, cross

- flow filtration, m icrofiltration, ultrafiltration, nanofiltration, reverse osmosis, etc. Essentially, the key process steps for treating the frac flowback waters can be categorized as follows:

-

 Clarification: Removal of suspend ed solids, oil & grease, microbiologicals, and di ssolved organics (in some cases). Removal of Fe++ may be included here since oxid ation to Fe+++ occurs readily in the presence of oxygen and Fe+++ can cause precip itation and fouling in downstream applicat ions 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 application s 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, e ither as Product

- 1 (cf. Figure 33 ) or as feed to membrane desal ination 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 bench

scale 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 significan tly reducing turbidity, TOC, Fe and Mn, as required for Product

- 1.

Figure 35 . Clarification of frac flowbac k waters. Results of bench

- scale experiments with the ―comp osite‖ Days 1

- 14 Woodford Site

- 1 sample.

In Figure 36 , the results of coagula tion 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 si gnificant solids content was deliberately chosen to illustrate the effectiveness of the coagul ation conditions. We ob serve that even this worst portion of t he flowback water was effe ctively treated by these conditions.60
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Figure 36 . Clarification of frac flowback waters. Results of bench

- scale experiments with the Day

26 Woodford Site

- 1 sample.

In Figure 37 , the results of coagula tion experiments with the Site

- 1 Day

- 1 sample are shown. As seen in Figure s 1 6 and 17 , the Day

- 1 sample had the highest total suspended solids (TSS) and very high total organic carbon (TOC) values relative to the ― composit e‖ Days 1

- 14 from Site

- 1 or the Day

- 26 sample from Site

- 2 . We observe in Figure 37 that the coagulation cond itions 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 w ith this Site

- 1 Day

- 1 sa mple.

Figure 37 . Clarification of frac flowback waters. Results of bench

- scale experiments with the Day

1 Woodford Site

- 1 sample.61
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However, when the supernatant liquid after flo cculation and settling was passed through a novel GE

- ultrafiltration membrane, the desired clarification wa s obtained, as shown in Figure 3 8

. The technique was also effective for the Day

- 26 sample from Site

- 2, although such extra clarification may not be necessary in this case.

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 sample s
. 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 F ree O il & G rease , Dissolved Organics and Volatile Organics

. In the data shown in Figure s 35

- 38 , we o bserve d that it is relatively difficult to reduce the TOC for the Site

- 1 D ay

- 1 water compared to the Site

- 2 Day

- 26 and Site

- 1 ―composite‖ waters. It is very likely that the natur e of the organics for the Site

- 1 Day

- 1 water is significantly different compa red 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 perfo rmance from isotherm experiments are plotted for similar ex per iments conducted with the Site

- 1 Day

- 1 sample and Site

- 1 ―Composite‖ Day s 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 pp m TOC, and (b) ―difficult‖ to remover organics down from ~30ppm TOC. This suggests to p ossibly different natures of the two sets of orga n-62
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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 indicat es that the ―composite‖ sample may be considered to be a diluted ve rsion 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 h exane so luble 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, incl uding 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 de veloped 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. In63
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this technique, 100 ml o f 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 metho d. 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 P oint. We notice the location of di ffer ent 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 magnit ude could be an indicator of the concentration of the organic contaminant (or fra gment), 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 an d boiling points (molecular weight) in the Site

- 2 Day

- 26 sample.64
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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 T OC met hods shown in Figure 17 are also reproduced in Figure 4 2

. We observe that the Site

- 1 Day

- 1 sample has more polar hydrocarbon compounds and also higher intensities. This corr esponds to higher total organic carbon in the Site

- 1 Day

- 1 raw water compar ed to Site

- 2 Day

26 sample. 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 con tent

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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 co nditions (time, mixing conditions). Samples were collected during these experiments and an alyzed by the above mentioned GCxGC

- MS method to evaluate the effect of the treatment method on app earance 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

w ere 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 h ydrocarbons found in the original Day

- 26 raw water, while Treatment 13 has significantly d iminished the intensities of the hydrocar bon 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 il lustrated 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 quantitativel y link the effectiv eness of any treatment method on the removal of particular organic species that are undesi rable 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 flo wback water sample. O bserve the appearance of peaks associated with surfactant molecules.66
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Figure 44 . Compa rison 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.67
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3.4.4 Process Step: ―Soften‖ The r e moval of ―hardness‖ ions, such as Ca, Mg, Ba and Sr, may be accomplished by precip itation methods, such as lime softening or membrane methods, such as nanofiltration that selectively reject the divalent and trivalent ions. The lime

- softenin g process, if properly d esigned would provide water recoveries in the range of >95%, which satisfies the requir ements in Figure 30. We evaluated nanofiltration via modeling with the GE Winflows me mbrane system design and simulation software 20 using techn ical performance data for GE‘s nanofiltration membranes. For the frac feed water sample analyses reported in Table 3, al though the removal of hardness was >80%, the water recoveries were in the range of 50~80%, which is much lower than the product specifi cations in Figure 30. Hence, we have focused our efforts on evaluating only lime

- softening for softening frac flowback waters.

Lime s oftening 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, cho o ssing the ―cold‖ mode will provide robustness to our conceptual process in handling frac flo wback waters from a variety of frac sites. The principles and process of lime softening are best explained on the GE Water website 21

. Hence, only a summary is provided below. When hydrated lime, Ca(OH)2, is added to the water being treated, the Mg++ ions are precip itated as Mg(OH)2. Noncarbonate or permanent calcium hardness, if present, is not affected by treatm ent 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 (NaCO 3 ) is a dded 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‖ Day s 1

- 14 samples are shown in Fig ure 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 si gnificantly reduce the hardness levels to meet the specifications for Product

- 2 and the pr etreatment levels required for desalination membrane processes. The process equipment required for precipitation softening are vessels with mixing equi pment to contact the feed water with the lime initially and then with soda ash. After sufficient contact ing, the precipitate is allowed to settle and the clear liquid is filtered. The settled so lids or sludge needs to be compacted to reduce the water content and lower the waste ha ndling 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 on

site versus the waste disposal costs need to be weighe d on an individual frac flowback site basis

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Figure 46 . Clarification of frac flowback waters with coagulation and ultrafiltration. Results of bench

- scale experiments with the Site

- 1 Day

- 1 and Sit e - 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 d etermine the amounts of lime & soda ash required and the amount of waste stream genera ted.

For the Site

- 2 Day

- 26 stream shown in Table 3, the amounts of Ca(OH)2 and Soda Ash r equired 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 wit hin 50 miles and transportation costs of $5/mile, the waste disposal costs are estimated to be in the r ange 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 w aste 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.69
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3.4.5 Desalination Membrane performance For Product

- 3 and Product

- 4, that requi re desalination t o 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 package 20

. Various me mbrane materials and system design configurations were considered to increase water pro duct recovery. The methodology is illustrated i n Figure 47 fo r 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 th at 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 corresponding ly increased from 68K ppm to 90K ppm TDS fo r these conditions. This has implications on overall system recovery and costs of the overall flowback water r ecovery process , as will be discussed under Task 6

. The increase in the number of stages and process complexity increases capital equipment cost s in terms of pumps, membrane mo dules, 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 stud ies using GE Winflows software 20

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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 fl ows heet 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 performan ce, costs and mobility for a 50

- gpm feed (frac flowback) mobile rig system. Technical perfo rmance evaluation inclu ded mass and energy balances, including waste generation and ha ndling. Costs included capital expenses for equipment and assembly, and operating expenses for amortization of capital equipment, rig

- setup labor, chemicals, membranes, power, and waste remova l. Mobility included the preliminary assessment of the rig configurations suit able 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 describe d earlier, treatment costs include C Setup (Cost of mobile rig transportation and setup at the frac site) and C Process (Cost associated with the capital and operating expenses related to the process steps). It does not include the cost of product

- and

conc entrate

- disposal. The labor costs associated with setting up the mobile rig are included in C Setup and thus in the C Treatment value. However, the rig operating labor for treating flowback water has not been included since these costs may be accounted dif ferently by different pr oducers as the rig may be run by operators handling multiple responsibilities at the frac site. We observe the following in Figure 49:71
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 The treatment cost, C Treatment <$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 di sposal, while cost of replacement membranes and electricity cost s 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 i mpact on the overall economics. What really matters is that the overall w ater recovery is improved while keeping the system capital costs low.

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 pr oject (cf. Figure 32) :

 Technical Performance: There is a high l evel of confidence that the conceptual processes will be effective to yield the Products

- 1,

- 2,

- 3 and

– 4 of desired quality since these pr ocess flow schemes were constructed based on the bench

- scale experimental studies on72
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the individual separation techno logies using actual frac flowback samples. Many of the initial concerns were mitigated by appropriate choice and verification of process opera ting 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 th e 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 var ious 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 t o 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.

 D emonstrate 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 Fi gure 50 . The rig co nsists 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 per meates through the membrane (called ―permeate‖). The remaining portion (called ―rete ntate‖) 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 independe nt parameters are:

 Feed composition

 Feed rate73
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 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 co ncentration in the feed tank essentially remain s constant since the retentate and pe rmeate 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 modules74
GE Global Research feed tank. This mode is useful for determining the mem brane performance prope rties 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 p referred 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 impli es lower pumping pressure r equirements.

 Salt

- flux parameter: This is frequently referred to as ―B

- value‖ in reverse osmosis li terature. A low value is preferred for this parameter as it implies low permeation of the salt species through the membrane, whic h 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. T hese 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 sol ution (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 high

selectivity 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 d esired 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 exper imentation 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 ab out 51%. Further recovery would have been possible but the experiment had to be stopped because of the low levels in the feed tank. Neverth eless, 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 to75
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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, na mely 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.76
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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.77
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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 d etails. As mentioned earlier, these parameters are useful for modeling large

- scale membrane mo dule 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 t o evaluate the effectiv eness 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 pre treated 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 desal ination 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 run s shown below in Figures 55

- 57 w ere 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 F igures 52

- 54 ).78
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After the Site

- 2 Day

- 26 sample run, the entire rig assembly shown in Fig ure 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 th e 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 pretreat ed Site

- 1 Day

- 26 field frac flowback sample and pure NaCl / de

- ionized water s olution

.79
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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 s olution

.

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

.80
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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 (pe rhaps 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 i mportant to observe from a fouling perspective. A steady d ecrease in performance over time would have indicated fouling of the membrane surface. However, w e observe similar chan ges in performance over the initial 24

- hour period for the two water solutions in Figures 55

, 56 and 57 . This indicates that there is i nsignificant 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 pote ntial fouling conta minants from the field frac flowback sample (at least for this field sample and under these desalination experimental conditions).81
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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 c onsideration (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 th e me mbrane desalination steps.
In Figure 58, the system configurations for the Conventional frac flowback disposal via u nderground Class II injection and the Flowback Water Recovery Process (FWRP) considered in this proje ct are described.

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 consi deration in this project.82
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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:

C FWRP < C Conventional 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 C FWRP
. 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.

Figure 59 . Cost parameters, units and correlations for the FWRP & Conventional processes d escribed i n 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 syst em 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 concent ration. This is illustrated for the Pro duct

- 4 quality ( 500 ppm TDS ) in Figure 60.83
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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 y Retentate = 70K ppm TDS while choice of pretrea tment & membrane system conditions for flowback recovery allow y Retentate = 90K ppm TDS, and thus higher recovery.

For Product

- 3, where the desired pro duct 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 se awater 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 dom inated 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 appropriate ly to meet the less stringent product quality. In other words, we select the Alternative 2 described above.84
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The main cost components, C Recovery , C Concentrate Disposal and the overall C FWRP 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 C Disposal . These values are normalized with respect to C Conventional . Thus, all regions with C FWRP /C Conventional <1 would be economically attractive for FWRP. We observe in Figure 61 that that C Recovery 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 comp onents.

T he C Concentrate Disposal increases as yF increases (and recovery decreases). T he increase in C Concentrate Disposal is much sharper because C Disposal is usually much higher than C Product delivery

. The net effect of the profiles of C Recovery and C Concentrate Disposal is that C FWRP increases with yF.

Figure 61 . Cost components for the membrane

- based FWRP: C Recovery , C Conc_disposal and C FWRP for the operating and cost parameters developed in this project and for an assumed value of C Disposal .

Definition of economical “Cut

- off” TDS for frac re

- use : The value of yF where the C FWRP crosses the C Conventional line represents the economical “cut

- off” TDS for that particular frac flowback site.85
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In Figure 62, the C FWRP for membran e

- based desalination mobile rig for producing Product

- 3 (20,000 ppm TDS) is compared to that for Product

- 4 (500 ppm) (previously il lustrated 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).

Figure 62 . Cost of membrane

- based FWRP vs. feed TDS concentrations forProduct

- 3 and Product

4 quality specifications.

This ―cut

- off‖ TDS is a strong function of the C Disposal , the cost of transport and disposal of the saline water in Class II disposal wells. This is illustrated in Figure 63 for a membrane desal in a tion mobile rig producing Product

- 4 quality (500 ppm TDS) where the C FWRP /C Conventional Disposal ratio is plotted as a function of varying C Disposal at different values of yF. The points where the curves intersect the solid black line representing C FWRP /C Conventional Disposal = 1 represent the ―cut

off‖ TDS at the yF and C D isposal values prevalent at the frac flowbac k disposal site under co nsideration.86
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Figure 63 . Profiles for CFWRP/CConventional for the membrane system vs. Concentrate disposal costs at varying feed TDS concentrations.

3.6.3 Hybrid Membrane+Ther mal 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 consi dered 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 p roduct

. The retentate with 90,000 ppm TDS is then distilled in a mobile evaporator (such as that i ntroduced by GE Water 22 recently) to obtain distillate with <500 ppm TDS and a concentrate with 280,000 ppm TDS. As seen in Figure 64, such a configuration y ields much higher reco very 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.87
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Figure 64

. Hybrid system incorporating pretreatment, membrane desalination and thermal disti llation 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 C FWRP for the overall hybrid system will have to be co nsidered. This is illustrated in Figure 65, where the C FWRP 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 C Disposal value in Figure 65, the Membrane system is cheaper than either of the other systems when the feed T DS 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 recove ry is much higher at 69% for the Hybrid case vs. 28% for the Membrane alone (cf. Figure 64).88
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Figure 65 . Cost profiles for the Membrane system alone, Mobile evaporator alone and the Hybrid membran e+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 ―cut

off‖ TDS is a strong function of the local C Disposal prevalent at the frac flowback site. For the Hybr id system the C FWRP /C Conventional Disposal ratio is plotted as a function of varying C Disposal at di fferent 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 C Disposal cases mainly due to the lower overall capital costs vs. the Hybrid case. However, the Hybrid case b ecomes more economically attractive as the C Disposal rises.89
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Figure 66 . P rofiles for C FWRP /C Con ventional ratio vs Concentrate disposal costs for varying feed TDS concentrations.90
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## 4 Summary and C onclusions

 Frac f lowback water is not a uniform ―raw material‖ from a p rocess 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 compo sition varies considerably depending on the geological fo rmation and operating conditions (e.g. chemicals introduced during the dr illing 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 Fayett eville and Woodford shales, whil e limited to very early flowback in Barnett, Marcellus and other shales.

 There is no clear consensus on product quality requirements for re

- use in hydrofra cturing. Based on feedback, 4 product options were identified, namely: Product

- 1 based on ―Clarifi ed 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 clar ification and hardness

- r emoval and able to meet the quality r equirements for Product

- 1 and Product

- 2

, and as pretreatment to the membrane d esalination process.

 A novel GCxGC+ ToF MS 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 w aters.

 RO membrane fouling experiments conducted using commercially available 2‖ dia meter spiral wound RO modules with pretreated flowback water sh owed identical w ater

- flux and salt

- rejection profiles as the control solution ( 35K ppm TDS NaCl in deio nized water ) . This indicated the effectiveness of the downselected pretreated cond itions i n removal of potential membrane foulants (inorganic salts and colloidal ino rganic 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 we re evaluated and optimized via performance modeling with GE Winflows software to increase w ater product recovery. For a feed solution composition similar to that obtained after pretreating (lime softened and filtered) Site

- 2 Day

- 26 sample , membrane system co nfigurations were identified that increased the recovery from 49% using the standard seawater

- desalination design to as high as 61.5%. The maximum retentate conce ntration correspondingly increased from 68K ppm to 90K ppm TDS for these cond itions. The increase in capital costs due to additional pumps, membrane modules, i nterconnected piping and controls for the new configuration w as more than offset by the increased water recovery when the overall FWRP was considered.91
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 The estimated Treatment C osts for t he four product options were within the cost cr iterion of < $2/bbl flowback, in line with preliminary feedback on customer expect ations. The cost estimations were based on reliable values obtained either from ve ndors or internal cost information for the d esired equipment. Other cost factors, such as costs of electricity, type and cost of labor, and waste handling & disposal, were a lso 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 transport ation & setup) while chemicals and solids waste disposal accounted for the remaining 18%.

 Cost s of the modeled overall Flowback Water Recovery Process (FWRP) were co mpared t o those for the conventional saline water disposal method

. For the desired economi c consideration of C FWRP /C Conventional  1 the ―cut

- off‖ feed TDS concentration would depend on the disposal costs prevalent at the frac flowback site. Higher di sposal costs would make FWRP attractive as seen in the sensitivity plots of C FWRP /C Conventiona l vs

. C Disposal at different feed TDS concentra tions. These charts thus pro vide a means of comparing the relative value of FWRP for a well flowback trea tment opportunity based on prevailing disposal costs and anticipated flowback TDS levels.

 The Hybrid membrane + t hermal approach

, wherein a 50

- gpm pretreatment & me mbrane desalination rig i s followed by a mobile evaporator to treat the retentate from the membrane unit

, provides much higher water recovery (e.g. 85% vs. 61% for M embrane alone for a feed con taining 35,000 ppm TDS). However, the H ybrid pr ocess 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 ec onomical for the lower C Disposal cases mainly due to the lower overall capital costs vs. the Hybrid case. However, the Hybrid case becomes more economically attractive for the high C Disposal 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 e xperiments on pretreatment and membrane desalination fouling conducted with typical frac flowback water samples from Woodford shale, me mbrane desalination system modeling, and cost analysis of the flowback water recovery pr ocess, we conclude :

 Technical Performance: There is a high level of confidence that the conceptual pr ocesses will be effective to yield the Products

- 1,

- 2,

- 3 and

– 4 of desired quality since these process flow sch emes were constructed based on the bench

- scale exper imental studies on the individual separation technologies using actual frac flowback samples. Many of the initial concerns were mitigated by appropriate choice and ver ification of process operating condi tions in the lab

- scale experiments.92
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 Cost Performance: The estimated Treatment C osts for the four product options were within the cost criterion of < $2/bbl in line with preliminary feedback on customer e xpectations. Using the CFWRP/CConventional  1 as t he 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 C FWRP /C Conventional vs. C Disposal at different feed TDS conce ntrations 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 vend or information on sizes and operations of the various equipment identified for the conceptual processes, and internal data on m obile rig operations, 50

- gpm mobile rig configurations may be achievable for the four products under consideration.

 Hybrid memb rane + thermal systems based on membrane desalination and a mobile evaporator may be attractive for treating Low

- TDS frac flowback water for high di sposal

- cost plays.

 It is believed that the parametric value assessment tool approach developed in this pro ject 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.93
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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 b ias/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 website 23

. 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 pr eferable 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 si tuations, such as wells drilled in reactive shales, dee p wells, and horizontal and e xtended

- reach wells, WBMs do not offer consistently good drilling performance. For these types of drilling situations at onshore sites, the industry relies primarily on oil

based muds (OBMs). OBMs perform well, but may be subje ct 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 alpha

olefins, poly alpha

- olefins, and linear paraffins. SBMs share the desirable drilling properties of OBMs but are free of polynuclear aromatic hydr ocarbons and have lo wer 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 compo nents 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.94
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 Other developments in drilling fluids could lead to e ntirely different formulations. Dril ling fluids based on formate brines have been suggested as being more environme ntally friendly than traditional fluids. Formate brines are created by reacting formic a cid with metal hydroxides. Common examples are cesium formate (HCOO

- Cs+), pota ssium 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 bari te 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 co ntrolled and monitored manne r into target shale formations above fracture pressure 24 . Fra cturing fluids used for fracturing gas shales include a variety of additive components, each with an engineered purpose to facilitate fractures and the production of gas 25 . Currently, the trends in shale wells are water based or mixed slickwater

- fracturing fluids. These are water‐ based fluids mixed with friction reducing additives 26 , which allows a fracturing fluid and proppant to be pumped to the target zone at a higher rate and reduced pressure tha n by using water alone. In addition to friction reducers, other additives including biocides are ut ilized to prevent micro‐organism growth and to reduce bio‐fouling of fractures. Oxygen sca vengers and other stabilizers which prevent corrosion of metal pipe s 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 hydrofractu ring is provided by D. Arthur et al of ALL Consulting 25 and are reproduced in Figures 18 and 19. Some of the operators have also published information on their practices, most notably, Chesapeake Energy 27 . 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 20 28

. From the flowba ck 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 pre sence and concentrations of these additives could be found. It is likely that these compou nds may get chemically, physically or microbiologically altered or destroyed during the hydrofra cturing process or become lost in the shale formation. Although some of these additives, such as guar gel, polyacrylamides, petroleum distillates may affect me mbrane performance; the actual impact would only have to be experimentally determined with flowback water sa mples.95
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Figure 67 . Volumetric composition of a representative hydraulic fracturing fluid excluding the proppants (repr oduced from D. Arthur et al., ALL Consulting 25 ).96
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Figure 68 . Additives in the hydrofracturing fluid (reproduced from D. Arthur et al, ALL Consulting 3 )97
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Figure 69 . Additives used in the hydrofracturing fluid, as reprod uced from information published by Talisman Energy, Inc 2898
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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 U nconventional 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=e f6a76d3e36931dc9ae8f983582e44e3

.

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 Ass essment of Marcellus Water Reuse

– Operations Manager Water R esources, 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, Environmenta l (Treatment Tec hnology) 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 Pl ays 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 Mob ile 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 Mud s 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, 2010.99
GE Global Research 14 John A. Harper. The Marcellus Shale

– An Old ―New‖ Ga s Reservoir in Pennsylvania. In Pennsylvania Geology, Volume 28 Number 1. Published by the Bureau of Topographic and Geologic Survey, Pen nsylvania Department of Conservation and Natural Resources. 2008.

15 P. Kaufman, G.S. Penny, and J. Paktinat, Critical E valuations 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 R esources, Co ldwater 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 Ana lysis Review, Pennsy lvania Department of Environmental Protection, Chap 95 Regulation, Independent Regulatory R eview Commission, p. 355, May 2010.

19 M. Tate and D. Adams, Waste Water Treatment Requirements, Regulatory Analysis Review, Pennsy lvania Departm ent of Environmental Protection, Chap 95 Regulation, Independent Regulatory R eview Commission, p. 7, May 2010.

20 GE Winflows memb r ane 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.

25 D. Arthur et a l. 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, Pen nsylvania Department of Conservation and Natural Resources. 2008.

27 Chesapeake Energy Company website: http://www.chk.com/Media/CorpMediaKits/Water_Use_Fact_Sheet.pdf100
GE Global Research 28 Talisman Energy (Fortuna Energy), http: //www.talismanusa.com/upload/media_element/26/01/microsoft

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