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ANADARKO PETROLEUM CORPORATION
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Will Discuss

Impact of make-up water composition on fracturing fluid 

design, considerations 

Make-up water constituents which are critical for fracturing 

fluid formulation

Matching of frac chemicals to make-up water compositions

Impact of blending flowback/production water with fresher 

make-up waters

Treatment of flowback/produced water for re-use

2
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Water Cycle in Shale Gas Plays

3
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Formulation of completion package 

Reservoir souring

Scale formation during pumping

Incompatibility with formation brine/formation rock in 

reservoir 

Scaling during flowback and production in near wellbore, 

production tubing, flowlines and facilities

Impact of Make-up Water Composition
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MAKE-UP AND FLOWBACK WATERS
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Problematic ions are Ba, Ca, Fe, HCO3 and SO4 (Causes of scales, 

incompatibilities and performance limits)

Reservoir is primary source for Ba and Ca, mostly for HCO3 also

Formation and/or corrosion can be sources for Fe 

Wells, ponds, creeks, rivers and some formations are sources for SO4

In general, reservoirs do not contribute both high Ba and SO4 unless 

brines from multiple zones are produced

This may be a problem in some areas where fluids from new 

developments are mixed with existing streams 

Good elemental analysis map of wells/flow lines is critical to water 

reuse as well as water management 

Problematic Elements
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Range of Key Elements in 

Fresher Make-up Water Sources 

Water from W. Texas Lake

Elements mg/l

Bicarbonate 110

Chloride 4072

Sulfate 2830

Barium 0

Calcium 850

Magnesium 360

Sodium 2410

Chloride 4070

TYPICAL RANGE OF KEY ELEMENTS IN 

FRESHER MAKE-UP WATERS-ALL AREAS

ELEMENTS

Concentration

mg/l

Ba++ 0-10

Ca++ 7-400

Fe++ 0-20

SO4-- 0-1000

HCO3- 0-350

FRESH WATER SOURCES in AREA 1

Primary 

Elements, mg/l

Municipal 

Waters

Creek/River 

Streams AMD Brines

Bicarbonate 97-207 12-30 0

Chloride 30-60 3-20 8-22

Sulfate 10-25 6-144 125-156

Barium 0 <0.03 <0.05

Calcium 12-35 7-38 21-35

Iron 0 0.1-1 2-3

Magnesium 4-7 1-15 13-17

Sodium 31-67 2-36 9-13

Strontium 0 0-0.2 0.10

pH 6.5-7.4 6-8 3-5
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Range of Key Elements in 

Flowback/Formation Brine

RANGE OF KEY ELEMENTS IN FLOWBACK/FORMATION BRINES

ELEMENTS Area 1 Area 2 Area 3 Area 4

Ba++ 0-12,340 0-35 0-110 0-1,200

Ca++ 7-50,000 65-6,000 10-1,100 15-17,000

Fe++ 0-230 1-250 1-300 0-320

SO4-- 0-150 0-500 0-300 0-960

HCO3- 0-470 150-450 50-1,500 50-800

Estimated Flowback

Volume, % of Pumped

15-20 <30 <30 <25
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DESIGN/FORMULATION 

OF 

FRACTURING FLUIDS
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Fracturing Fluid Design/Formulation

10

Fracturing Fluid Design Decision • Slick Water

• Hybrid System

• Gel

Water Sources • Fresher make-up

• Flowback/Produced 

• Blends

Fracturing Fluid Formulation • Friction reduction

• Bacteria control

• Scale control ?

• Others ?
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Friction reduction / proppant transport 

Slickwater: polymers

Hybrid (gel + slickwater) & Gel: Polymers, X-linkers, 

gel breakers, pH control, etc. 

Bacteria control 

Scale management – to be evaluated case by case

Clay control – as needed

Surfactants – as needed

Others

Fracturing Fluid Formulation - Functionality
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Flexibility in water and product selection

Almost all flowback waters can be used

Both anionic and cationic polymer packages are utilized 

Tolerance to high salt and divalent ions can be accomplished by 

controlling % of ionic charges on polymer and/or molecular 

modification with more salt tolerant polar groups such as 

sulfonate

Flexibility in selection of bacteria control products

Less prone to scale formation but some constraints in scale 

inhibitor selection if cationic FR is used

Anionic FR constrains use certain organic clay control products

Compatible surfactants are available for anionic and cationic FRs

Slickwater Formulation
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Friction Reduction Results for High Salinity Brine, 

Fresher Water and Blends – 2 Vendor Products

November 14, 2012 13

% FRICTION REDUCTION @ VARYING DOSAGE RATES (gpt) 

in DIFFERENT BRINES

FR DOSAGE 

RATES, gpt

MAKE-UP WATER

TDS, 

ppm VENDOR 1 1.5 2

Fresh Water 0.7K Vendor A Product 70

Vendor B Product 77 77 76

Blend Vendor A Product 70

3 FW+1FBW 38K Vendor B Product 49 70 70

Blend Vendor A Product

1 FW+1FBW 76K Vendor B Product 60 72 70

Blend Vendor A Product 70 69

1 FW+3FBW 114K Vendor B Product 57 67 68

High Salinity Brine 152K Vendor A Product 69

Vendor B Product 45 51 37

WATER DATA

Fresh 

Water

High 

Salinity 

Brine

Elements mg/l mg/l

Bicarbonate 112 230

Chloride 100 90000

Sulfate 200 X

Barium X 7000

Calcium 65 11400

Magnesium 15 800

Iron X 100

Potassium 15 200

Sodium 100 40000

Strontium X 2500

TDS, mg/l 0.7K 152K
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Friction Reduction Results in Area 2 Flowback

Brine, Fresher Water and Blends 

% FRICTION REDUCTION WITH VENDOR C PRODUCT 

IN AREA 2 BRINES @ 2 Reynolds Numbers

63000 41000

FR Dosage Rates, gpt FR Dosage Rates, gpt

MAKE-UP WATER 0.75 1.0 1.5 0.75 1.0 1.5

Fresh Water W-1 75 75 73 58 68 67

Blend W-2 73 75 75 59 57 64

Flowback Brine W-3 73 75 74 54 63 61
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Hybrid System Formulation

• Hybrid gel

– Slickwater & guar, or SW & CMC 

– Variations in % of SW, linear gel and cross-linked gel 

Guar and CMC gel systems

Linear guar and/or its derivatives or CMC and/or its derivatives

pH adjustments: Guar (pH=8-10); CMC (pH = 5-7) 

Cross linkers, breakers, pH adjustment products, biocides, scale 

inhibitors, surfactants

Gel systems are impacted by multivalent ions in particular 

by cations:

Fe, Mg and Ca are likely to drop out as carbonates/hydroxides in 

order to increase pH to 8-10 for Guar system

pH of flowback/produced water is more favorable for CMC system 

however CMC gel system is impacted by multivalent cations which 

compete for negatively charged segments of polymers 

November 14, 2012 15
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Use of Flowback Brine for Gel Boragel System: 

pH Adjustment in Area 3 Flowback Brine 

November 14, 2012 16

AREA 3 Flowback Brine

Elements mg/l

Bicarbonate 735

Chloride 18,000

Sulfate 60

Barium 35

Calcium 450

Magnesium 70

Iron 30

Potassium 200

Sodium 10,000
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Bacteria Control

November 14, 2012 17

Second most important element of fracturing fluid package

Product requirements

Compatible with completion package/reservoir conditions 

Effective initial kill and prolonged protection

Meet/Exceed Environmental, Health and Safety requirements

Cost effective

Options

Non-oxidizing biocides

Oxidizers

Non chemical means

Combinations of above

Recommendations

Select products/methods to meet criteria and test 

products/methods using actual fracturing packages

Employ aggressive performance monitoring program

More and more on the fly application
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Establish scale control needs

Initially, we do not have sufficient data on reservoir/reservoir and 

flowback fluids to determine if scale control is needed

Carry out very rigorous flow back monitoring programs to learn about the 

reservoir/reservoir fluids

Determine where and how much scale will form?

Use data on fluids and conditions to examine scaling issues for all 

potential scenarios from blending stage to a time in the future that 

production is stabilized 

Can you do anything about it? 

Driving forces for scale formation may be too strong to prevent scale 

formation

Do you want to control scale partially/completely and where?

During blending/pumping, in reservoir, near wellbore, downhole in 

tubing, flowlines, facilities

Screen SI products under realistic conditions

Implement monitoring program to verify product effectiveness/optimize SI

Scale Management/Control Decision
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Potential Solids Upon Injection of Area 3 Flowback Brine 
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Potential Scales from W. Texas Lake Water if it is Injected 

(Based on 1 STB of Water)

November 14, 2012 20

Water from W. Texas Lake

Elements mg/l

Bicarbonate 110

Chloride 4072

Sulfate 2830

Barium 0

Calcium 850

Magnesium 360

Sodium 2410

Chloride 4070
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Total Calcite from a Daily Well Stream 

(4 bbl of formation water, 600 Mcf gas and 140 bbl of Oil) 
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Scale Tendency of Calcite for a Daily Well Stream

(4 bbl of formation water, 600 MCf gas and 140 bbl of Oil) 
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Scaling Tendency of Area 1 Flowback Water 

and Fresh Water Mixture (97% Fresh/3% Flowback)
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0

20

40

60

80

100

120

0 25 50 75 100 125 150 175 200 225

SI Inhibitor Efficiency (%)

SO4 Concentration (mg/L)

SI Efficiency With Slick Water Additive Package @ 140F 

Fixed Ba @ 7000 mg/l, vary SO4

2000ppm SI

1500ppm SI

1250ppm SI

1000ppm SI

750ppm SI

500ppm SI

250ppm SI

Scale Inhibitor Evaluation for Area 1 Completion Fluid 

Package: Ba fixed @ 7000 ppm, SO4 Varied
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IMPACT OF MIXING FLOWBACK BRINES 

WITH 

FRESH MAKE-UP WATERS 
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Impact of Mixing Reclaimed Area 1 Flowback Brine 

with Various Fresh Make-up Waters from Area 1

0

2000

4000

6000

8000

10000

12000

14000

0 0.2 0.4 0.6 0.8 1 1.2

Solids (BaSO4 & CaCO3), lb//100K STBW

Fraction of Area 1 Flowback Water

Solids Can be Generated per 100K STBW Frac Job upon Mixing of 

Area 1 Flowback Water with Different Fresher Brines @ 150F & 3000 psia

BaSO4 Ave Ions AMD Brine with A1 FlowBack Water

BaSO4 Max Ions Creek Water with A1 FlowBack Water

CaCO3 Max Ions Utility Water with A1 FlowBack Water

BaSO4 Max Ions Utility Water with A1 FlowBack Water

CaCO3 Max Ions Creek Water with A1 FlowBack Water

AREA 1 WATER DATA

Flowback

Brine

Elements mg/l

Bicarbonate 25

Chloride 65000

Sulfate 0

Barium 2650

Calcium 9650

Magnesium 660

Iron 17

Potassium 250

Sodium 22470

Strontium 3230

pH 9.1
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Water Treatment For Reuse

Water coming from formation is most compatible with the formation

No or minimal treatment of flowback/produced water is needed

Remediation of flowback/produced water primarily depends on 

fracturing system used and conditions at target zone but should include 

Bacteria control

Removal of organics, total suspended solids (TSS) and Fe

A typical Effluent Specifications:

Fe <10 ppm

TSS <50 ppm

Hydrocarbon content <40 ppm

100% bacterial control

pH = 6.5-7.5

27
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Broad range of products are available to formulate a well performing 

fracturing fluid in most brines 

Minimize the number of chemicals and quantities utilized (2-3 

essential chemicals) 

Friction reducer 

Bacteria control products 

Sale Inhibitor – valid assessment is needed 

Clay Stabilizer – generally not needed if flowback water is used

Surfactants – Fit for purpose application

Reuse of reclaimed flowback brines and produced waters offer 

technical advantage for controlling scale and preventing clay swelling

Hybrid systems may require removal of some of the cations such as 

Fe, Mg and Ca since they impact product performance 

However, reclaim water can be used for acid or in slickwater stages 

while fresher make-up waters can be used for gels

Summary
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Adjustments to completion packages are not well managed in a timely 

manner due to insufficient information on make-up water and formation 

fluids, short lead-time, limited product lines of fracturing company/vendor, 

lack of knowledge, etc. 

Aggressive fluid sampling/analysis programs should be implemented in new 

developments until the area is fully understood

Aggressive product evaluation program, with vendors and potential product 

suppliers, should be in place to continuously improve product performance, 

economics and environmental acceptability.

Even though in wells certain salinity ranges are reached, it is difficult to 

define formation brine unless amount of flowback and/or produced water 

exceeds total injected fluid. Equilibrium values will change with time.

Summary (cont.)
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QUESTIONS/COMMENTS