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International Water Conference (DCN SGE01073) Workshop: Water and Wastewater Treatment for Natural Gas Well Development November 17, 2011

Presenters: John Schubert, HDR Joe Swearman, CONSOL Energy

– water and wastewater management. Works on shale and coalbed methane.Not responsible for well completions.

Background Page 10. Note that compared to AMD and some surface waters, shale formation water is very low in sulfate (SO 4 ).

Page 18. reference Hefley, W. E., et al. 2011. The Economic Impact of the Va lue Chain of a Marcellus Shale Well . Working Paper, Katz Graduate School of Business. Pittsburgh, PA: Katz Graduate School of Business, University of Pittsburgh. Copyright © 2011, University of Pittsburgh

Typical installed cost of a horizontal Marcellus well $4,000,000 to $5,000,000 Gas production expected 3 to 4 billion cubic feet Current gas price, approx $4.0/mcf Value of gas to be produced $8,000,000 to$16,000,000

Typically cited costs for all water supply/disposal Functions for a horizon tal well, nominally 10% to 20% of well cost

Much of the cost is transporting water to and From the well site

(water costs exclude frac chemicals)

Page 21 Fracturing typical pressure is 9,000 psi, pumping 75

– 100 bbl/min Demarkation of flow back from produced water: when the well “starts gassing”

Sequence of events
1. Site clearing, may need cut and fill to level site, create a road access Install pit for drilling and fracking, get frack tanks onsite Pits installed by CONSOL are lined, with leak detection wells and monitoring Freshwater supply pits don’t have same construction requirements as flowback pits. Flowback pits must be reclaimed after operations are complete.
2. Drilling: $2 to $3 million; lasts about 30 days
3. Fracking: $1 million /well; lasts a week or so
4. Flow back: maybe 2

– 3 weeks. Each activity may be done by a separate company

Water is needed for drilling, about 10% of the amount needed to frac.2

Induced seismic activity Presenters scoffed at the idea that fracking could ind uce seismic activity, but noted that disposal wells taking large volumes of water, may lubricate faults, resulting in some activity. Case at the Rocky Mountain Arsenal, haz waste disposal, seismic activity.

Well installation Longer horizontal legs (incre asing from 5,000 ft to 10,000 ft) reduce costs.

Frack water chemicals

– friction reducer

Page 31 and Page 33 Polyacrylamides are used to reduce friction from high rate pumping. TDS toleration varies by brand. A new brand announced it could be used with >100,000 ppm TDS. Friction reducers that can be used in very high TDS waters reduce costs by allowing water reuse.

Proppant and Gel

Pages 34

– 36 Flow velocity helps keep sand in suspension. Gel is also used t o keep sand in suspension. The gels need to breakdown (using chemical breakers) so the slick water can flow back. Typically ammonium persulfate chemical oxidizer used to break the gel. In Marcellus, 10

- 20% comes back. Formation water is hot, up to 160 F

.

Although AMD has some benefits as a frac water supply, its high sulfate creates scaling issues with the high barium conc in Marcellus formation water.

Source water requires very little treatment, except maybe some conventional filtration, conducted o n site.

Page 47 The first water back out of the well is the “freshest” (lowest salt). Increases from 0 to 90,000 ppm over 80 hours. In comparison, CBM flow is more constant in volume: it comes from a continuous surface flow into the coal seam.

Page 53 Cost of deep well disposal Disposal: $0.75 to $2 per bbl Disposal, including transport $4 to $6 per bbl Pretreatment not required before shipment

Page 56 PA discharge requirements would require highly advanced treatment. “brine treaters ” (CWTs) removed Fe and Ba. Some discussion of whether they were still operating.3

Flowback water reuse Most flowback water is reused Keeping frac water onsite limits environmental liability Some operators do NO treatment prior to reuse, just mix with f resh water, or limited SS removal Some producers only want fresh water

Page 60 Solids concentration are highest at the start of flowback Polyacrylamides (gels used to keep proppant in suspension) at 1% will make particles dispersive: they won’t settle. Polyacrulamides must be either diluted or destroyed to get good TSS removal.

Page 63 Scalants

– contentious Concentrations vary hugely. In north

- central PA, Ba is very high.
BaSO 4 is only soluble at a few ppm; it is inert in the environment (won’t leach from solids sludges) Sludges with BaCl, BaOH, BaCO 3 will leach. Would fail TCLP.

There is no industry standard for Ba in frac fluid make up One operator (CNX) doesn’t care Another requires Ba <200 mg/L (concentration in the Mon. River)

Page 69
NORM

– if treating produced water, the NORM will concentrate in solids, but the concentration is less than the landfill limits, so there is not a practical concern for disposal or worker exposure.

Page 73

- 74
TOC Wet gas areas in western Marcellus can have higher TOC in the produced water There is not presently a market for natural gas liquids in Marcellus. The condensates may be collected and barged to Texas for processing. FERC limits the btu in natural gas, liquids have higher btu, so they must be removed.
Dr y gas areas of the Marcellus, TOC is <100 ppm

Page 75 Ammonia Can be a problem if the wastewater is going to be evaporated. Ammonia will be driven into the distillate (wastewater condensate) maybe undesirable, depending on use.

Page 79 Iron removal
Ge t iron to Fe +3 (oxidize it )for lower solubility Adust pH to ppt (be watery of arlylamides: the ppt may not settle)4

Pg 80

– 85 Softening (removing Ba, Ca, Mg) High operating costs Conventional clarifiers are large not mobile 1⁄2 gpm /ft 2 needed to remov e Ba or softening solids

Alternatives Veolia acti

- flow (truck mounted) Mix ppt with polymer/sand, to hydrocyclone Expensive, to achieve a high concentration solids stream requires thickening Timing tricky for polymer selection

Siemens high rate clarifier, using media in clarifier Can settle at 1 gpm/ft 2 Truck mounted, easy to get on site Disadvantage: sludbe accumulation hard to remove, gets too dilute

Others available, but effectiveness not yet verified.

May need filtration for effective sol ids removal, but require operator attention Sand, multi

- media

– but these are cumbersome, have to manage the back wash water bag & cartridge,

-- good back up to clarifier

Page 86
RO Historical limit for using RO is seawater concentrations, 3.5% to 4%
Re cent developments up to 4.6% But applicability in Shale Gas limited by TDS May be usable for early flowback, before TDS increases

Page 87

– 88 Vapor Compression No boiler required, cost savings compared to systems requiring steam Use a generator set to pr oduce electricity to run the compressor and heater Limitations: 250,000 TDS on concentrate or salts will precipitate. Truck mounted units that run 25

– 50 gpm/unit are available.

Pages 90

- 92 Crystallizers Run on steam, with some mechanical compression, but need heat. Requires specialized metallurgy (corrosive salts) Road salt specifications: 95% NaCl, <1% moisture, defined particle size

Electro

- coagulation Useful where there is an organic problem. Doesn’t make sense for Mg removal Vendor: WaterTectonics (has agreements with Halliburton) Results in small reduction in hardness (Ca, Jg), Fe, disinfection, fines, TSS $2/bbl5

IWC 11

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The Real Cost of ZLD for Shale Gas Frac Water in the Marcellus Shale Play

WILLIAM A. SHAW, P.E. HPD, LLC, a Veolia Water Solutions & Technologies Company, Plainfield, Illinois

bill.shaw@ veoliawater.com

International Water Conference, November 14

– 17, 2011.

Key points from the presentation

 Brine disposal can amount to 50% of SG E wastewater treatment costs, so minimizing volume is important to reduce wastewater management costs.



###  Because of the high salt content, SGE wastewater is highly corrosive, requires special metallurgy.



###  T 

### he use of Reverse Osmosis to treat the equalized frac water is not feasible due to osmotic pressure limitations.

 

### E vaporator design must take into account the propagation and growth of crystals within the bulk solution. Falling film evaporators can handle at most a few percent suspended solids in
the recircu lating brine without severe fouling and plugging problems, so it is necessary to operate the evaporator below the solubility limit of the least soluble salt, in this case,
sodium chloride.

 

### Brine waste haulers generally charge by the hour including waiting and loading time at the drill site, round trip driving time to the injection well, and waiting time to unload at the disposal site. Reported charges vary from $150 to $200/hr. Including tipping fees assessed by the injection well operators of about $2/bbl, the cost to dispose of concentrated brine originating at Pennsylvania drill sites in Ohio injection wells will easily cost $15/bbl ($0.36/gal).

 

### To reduce disposal costs, an alternative is centralized crystallization following on

- site evaporation. Crystall ization requires a steam plant and cooling towers, so on

- site is not
feasibile. Shaw assumed “centralized” means within 50 miles of the well with on

- site
evaporator.

 Ca, Mg, Ba, and Sr

- Cl don’t precipitate well. A better strategy is to use alkaline precipi tation (with lime and sodium hydroxide) to ppt these species, leaving mostly sodium chloride for crystallization.

 Shaw estimated a centralized softener/crystallizer system will cost $0.52/gal ($22/bbl ). This analysis shows that the softening/crystallizatio n/ landfill approach has a higher total cost than transporting the concentrated brine to an injection well in Ohio.

 Shaw suggested an alternative process, cold crystallization, operated under vacuum and without the chem ppt step. He estimated the cost as 

### $0.26/gal ($11/bbl), half the cost of the softener/crystallizer/ landfill system, and 25% less than the cost of deep well disposal in
Ohio.6



### Discussion Dan Dudack, Siemens, Canonsburg, PA

Questions:

 

### W ill Ba concentrations up to 16,000 ppm crystallize in the cold crystallizer? Shaw said yes.

 

### Ca n the salt from the crystallizer be sold or otherwise used, rather than landfilled?
Or is it hazardous? Shaw noted that salt from the crystallizer is too fine to be used directly as road salt
and w ould need to be pelletized to be used as road salt. He noted that the value of road salt is low and this use would not be cost effective. He explained that landfills used for salt disposal are monocells with infiltration control and leachate recovery.

 

### Not ed that PA has 6 disposal wells, with two more coming on line. Also, currently, most produced water is used in fracking new wells. But when PA becomes “water positive” how will build the centralized thermal units? Shaw’s Response: not the gas producers. Maybe the water industry, or a 3 rd party. Shaw suggested that Veolia might operate it as a “merchant plant” but would need some
“anchor tenants.”

 How does the crystallizer manage variability? Response: need good equ alization. Also noted that evaporation and crystallization are designed and controlled on the amount of water you want to remove.

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NORM Removal from Hydrofracturing Water

JAMES SILVA, HOPE MATIS, WILLIAM KOSTEDT IV, and VICKI WATKINS

GE Global R esearch Center, Niskayuna, NY

International Water Conference, November 14

– 17, 2011.

Key points from the presentation

 NORM Analytical Methods

o 

### Alpha

- beta proportional counting did not yield consistent results (high salt interference)

o 

### LSC was successful for measuring radioactivity in liquid samples, but because it measures both alpha and beta, counts change over time as the parent7 

### isotopes decay. For the day

- to

- day measurements in the study, Silva used LSC calibrated to gamma spectrometry.

o 

### Gamma spectrometry with a high purity germanium detector is effective for measuring 226 

### Ra activity in both solid and liquid samples. The advantage of gamma spectrometry is that it can discriminate among gamma

- emitting species. On the other hand, gamma spectrometry does requ ire larger sample sizes; 500

- 1000 mL is typical for liquid sample analyses.

 

### Table 2 presents pollutant concentration data for 6 Marcellus wells and 1 Barnett well, including 226 

### Ra

 

### Adsorption of 226 

### Ra to commercially available Dowex RSC resin, from high bar ium and high TDS frac water, was not great enough to be lower cost than deep well injection of untreated frac water.

 

### Research continues with inorganic oxide

- based resins.

Discussion JERRY L. PENLAND, Chester Engineers Technology Group, Pittsburgh PA

 Two references were provided that show the sorption of radium onto b arium sulfate is the preferred sorbent. Methods for removal of the radium from the sorbent are also discussed with removal efficiencies being quantitative. Discusser suggested co

- ppt of Ba and Ra for radium removal. Author’s response: this is a new matrix (very high TDS and Ba), not what was tested in the references. Literature is focused on drinking water treatment.

 A commenter noted that currently, 97

– 98% of frac fluid is reused. Also, for every 5 barrels of water used to frac, only 1 is returned. Flow back is 5

– 7 barrels/day. Most operators want simplest disposal strategy (DWI). They may want to reduce transportation costs, but they don’t want to deal with cleaning up the flow back. Author’s response: costs of long range trucking must be balanced with costs for reuse.

 Question: how are flow back and produced water distinguished/defined? Answer: The flow returned 1

– 21 days after fracking is “flow back.” It has relatively low TDS

com pared to produced water. Silva indicated he has data of days after frac vs: flow volume, Ba conc, TDS

. Also, the distinction is often administrative: which budget is used to managing the wastewater.

 Question: will produced water flow decline from 7 bbl/d ay? Answer: The 7 bbl/day represents near term post

- fracking. The 13 vertical wells in New York State that were hydraulically fractured in the 1990s now produce 1,000 gal/year.8

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- 08 Evaluation of Brackish Groundwater Treatment for Use in Hydraulic Fracturing of the Bakken Play, North Dakota Bethany Kurz, Daniel Stepan, John Harju, Brad Stevens, and Robert Cowan Energy & Environmental Research Center Grand Forks, North Dakota

 Provides background on hydraulic fracturing for shale OIL recovery.

 Describes difficulties operators experience in obtaining water supply to make up fracking fluids in arid western North Dakota. The state has limited industry access to surface aquifers and
Missour i River water is distant from some fracking sites. The cost to purchase raw water ranged from $0.25/bbl up to $1.75/bbl, and the cost of transporting that water to the fracture location ranged from $0.63/bbl up to an estimated $5.00/bbl.

 Presentation descr ibes a pilot RO system used to treat brackish groundwater (8200 mg/L TDS) for use as fracking make

- up. Pretreatment included sand filtration and GAC. System included cooling the feedwater from 155F to 90F.

 The concentrate was used in the oil recovery proc ess (for formation flooding).

 The hot, salty feedwater is corrosive. Corrosion testing concluded that investment in stainless steel (but not Hasteloy or Ti) would be warranted.

 The pilot tests were successful and the industrial partner decided to build a f ull

- scale water treatment unit. The additional cost to obtain water was more than offset by reduction in transportation costs. GE will own and operate the RO unit and sell water at $1.32/bbl.

Discussion JOHN SCHUBERT, P.E, Senior Process Engineer HDR, S arasota, Florida

 Schubert noted that the quality of the brackish water that was treated in this study is suitable for fracking in the Marcellus. He asked why treatment was required. Answer: Author could not answer the question.