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Richard Goodwin, Ph. D., P.E.'s picture
Environmental & Energy Engineering Consultant self-employed

Richard Goodwin, PhD, is an Environmental Engineering Consultant . Dr. Goodwin has more than 25 years of experience in the waste treatment, disposal, by-product utilization, conducting studies on...

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  • May 20, 2018

During the past 30+ years USA energy fuel usage has changed from predominance of coal and foreign oil to shale Natural Gas and Oil. In addition, both the technology and role of wastewater treatment firms have evolved from specialized product line to comprehensive menu of unit operations – capable of reducing effluents approximately drinking water quality. Such changes enable Original Equipment Manufacturing [OEMs] to offer turn-key projects including Operation, Maintenance and Performance Guarantees. Artificial Intelligence [AI] facilitates autonomous operation through use of self-correcting algorithms to achieve contracted levels of operation and performance. Incorporating Reuse Recycle in new energy facilities [horizontal drilling – hydraulic fracturing, Natural Gas-fired Power Plants] promotes their acceptance in arid regions [e.g. Middle East] and while disparaging bans.

An approximate 10% increase to Operating Expenses can be accommodated for hydraulic fracturing systems due to oil [WTI] exceeding $60/bbl. Similarly, for new Natural Gas-fired Power Plants Combined Cycle Gas-Turbine [CCGT] promoted by Shale Gas the increased plant capital cost would be approximately 10% [5% to 15% of the total plant cost] with an increase of annual operating costs by 0.1%, incorporated at a spot Natural Gas price below $3/MMBTU – without affected profitability and expected earnings.

Shale gas, derived from hydraulic fracturing and horizontal drilling, has yielded a market price of under $3/MMBTU for the past few years – from $12/MMBTU in 2008 – a 75% reduction resulting in 40% cut of CCGT operating costs. Enabling incorporation of Reuse Recycle and dry cooling to reduce raw water use; improving siting acceptance for drought and arid regions. Low cost natural gas generated from hydraulic fracturing and horizontal drilling supports converting older coal-fired power plants into natural gas fired units – especially Combined Cycle Gas Turbine. This trend of continued reliance on shale gas for base-loaded power plants will continue; placing greater emphasis on horizontal drilling and hydraulic fracturing – changing our environmental priorities. The siting of new drilling facilities and power plants offer an opportunity to comply with wastewater discharge regulations and water scarcity by adopting reuse recycle management. Horizontal drilling and hydraulic fracturing, also, released abundant shale oil in the form of light tight oil; however, not all USA refineries are capable of processing this type of crude oil – limiting expansions and retrofits. This discussion focuses on Shale Gas production facilities and gas-fired power plants wastewater issues i.e. reuse and recycle. 


Horizontal Drilling and Hydraulic Fracturing - Wastewater

Water use in unconventional shale oil and gas extraction can be complicated. The hydraulic fracturing process can use more than 5 million gallons of water per well and resultant wastewater discharges.

After the completion and stimulation of shale oil and gas wells, fracturing flowback water, the portion of injected hydraulic fracturing fluids that return to surface before production, returns to the surface quickly over a few weeks and shows a rapid decline in quantity and quality (typically 10-30% returns in the first 1-2 weeks). Flowback water often contains very high total dissolved solids (TDS) and is characterized by the presence of sand, clays, polymers and chemistry associated with the drilling and completion of the new well. Shale produced water (i.e. water produced during oil and gas production), on the other hand, requires management in the longer term. Produced water flow rates are typically much lower and more consistent than flowback, is variable field-to-field and well-to-well, but has generally predictable flow rates and quality.

In the Permian Basin the ratio of produced water to oil has dropped from 8:1 to 4:1 [due to normal decline per well] for the remainder of 2018 about 350 million barrels of product water per month will be generated. Operators can remove Total Dissolved Solids, oil while oxidizing bacteria, iron and sulfide at less than $0.05/barrel. The ultimate goal of treating production wastewater approximating drinking water is estimated as less than $050/barrel.

This flowback water contains hydrocarbons, minerals, residual hydraulic fracturing chemistry and other substances originating from the shale itself. Flowback water must be collected and securely contained before it is either recycled or disposed. Technologies exist to treat flowback water to be recycled into the next hydraulic fracturing job, remove contaminants before disposal, and improve water quality to meet discharge and re-use standards. Application specific examples include selective ion exchange for boron removal for "gel fracs", self-cleaning fine particle filters to remove suspended solids, polymeric adsorbents for organic compound removal.




Gas production through fracking generated about 35% as much wastewater per unit of gas recovered as wells where conventional drilling was employed. On average, the amount of wastewater produced by fracked wells exceeded about 10 times that generated by conventional wells but the former also delivered about 30 times more gas..

A typical fracked well can use more than 4 million gallons of water during its lifetime to force natural gas out of the ground. The water is often mixed with chemicals, making it impossible to reuse immediately for fracking. Options for this wastewater include: transport off-site to centralized treatment facility or deep well disposal, on-site treatment followed by recycling.

The costs for hauling away wastewater for deep-well injection range between $3 and $7 per barrel ($0.35 to $0.85 per cubic metre). For a newly fracked well, the cost could reach $100,000 for transporting over 14,000 barrels (1,670 m3) of flowback – water levels produced from each basin, and indeed, each wellhead can vary. Plus, an additional potential 3400 barrels (405 cubic meters) each day of transported produced wastewater, at $20,000 per day.



Recycling frac waters would not only save operators money and secure ‘fast track’ permits, but reuse would avoid deep well injection – removing a high potential contributing factor to localized earthquakes.

Research confirms the relationship of deep well disposal to localized earthquake – not hydraulic fracturing. In July 2014, research team at Cornell University has discovered that the earthquakes in Oklahoma are a result of subsurface wastewater injection at disposal wells.

“the process of hydraulic fracturing a well as presently implemented for shale gas recovery does not pose a high risk for inducing felt seismic events. Injection for disposal of waste water derived from energy technologies into the subsurface does pose some risk for induced seismicity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation”. Subsequent peer review investigations have confirmed that “the sharp rise of Oklahoma seismicity since 2009 is due to wastewater [from Enhance Oil Recovery and saltwater disposal i.e. hydraulic fracturing]”. 



Combined Cycle Gas Turbine – wastewater

Throughout the latter decades of the 20th Century, power plant chemists and technical personnel primarily had to deal with the following parameters in various plant discharges:

Oil and grease (O&G)


Total Residual Oxidant (chlorine, bromine, or chlorine dioxide in the cooling water discharge)

Total suspended solids (TSS)

State regulators may impose limits on other cooling water discharge constituents, and regulations are now emerging that include limits on the following constituents:

Total dissolved solids







Quantity of discharge

Treatment processes include:

Micro- or ultrafiltration (UF) to remove suspended solids in the waste stream.

Sodium bisulfite (NaHSO3) feed to remove residual oxidizing biocides.

A sodium softener to remove calcium and magnesium.

Sodium hydroxide injection to elevate the pH above 10. (The combination of hardness removal and pH elevation keeps silica in solution.)

Two-pass reverse osmosis (RO) treatment to recover 90 percent of the water

Advanced Technology – wastewater reuse recycles


Wastewater Reuse Applications and Technologies


Media Filter –

Solids < 5-10 mg/L Turbidity < 1 NTU Particles 2 - 5 micron 98% removal Requires coagulant or flocculent Feed


Microfiltration –

Completely remove unwanted solids greater than 0.1 micron BOD < 5 mg/l, TSS < 1 mg/l Turbidity < 0.2 NTU


Membrane Separation 

 There are six commercially used membrane separation processes; Microfiltration (MF), Ultrafiltration (UF), Nanofiltration (NF), Reverse Osmosis (RO), Dialysis, and Electrodialysis (ED). Membrane processes can be classified based on membrane separation size and mechanism, membrane material and configuration, or separation driving forces used. Membrane processes utilize set terminology to discuss membrane performance. The rate of fluid transfer across the membrane is referred to as the flux, and has units of kg/mh. The pressure experienced across the membrane is referred to as the trans-membrane pressure (TMP). The fluid that passes through the membrane is the permeate, while the flow retained by the membrane is the retentate. Separations based on membrane pore size include MF (0.1- 0.2 μm), UF (0.002 – 0.1 μm), and NF (0.0001 – 0.001 μm). The ranges are not strictly defined and some overlap exists. These three types of filtration rely on a sieving action to remove particulate matter. In comparison RO membranes have a pore size of 0.0001 – 0.001 μm, but rely on the rejection of small particles by an adsorbed water layer rather than physical straining. All four varieties of membranes rely on hydrostatic pressure differences to drive the separation process.



Autonomous Control System – Turn Key


The conceptual advanced waste treatment system lends itself to autonomous control using a back-feed algorithm system based, on wastewater chemical physical parameters. Each unit’s operation and performance can be modified using downstream performance from respective, specific algorithms. Autonomous control facilitates on-site operators – reducing operating costs – while ensuring OEM guaranteed, effluent performance. The application of AI or self-learning algorithms enables the system to autonomously correct operation and performance. Autonomous operation reduces on-site personnel and annual costs.


Oil water separation

separate gross amounts of oil and suspended solids from the wastewater effluents of oil refineries, petrochemical plants, chemical plants, natural gas processing plan

Electrolytic Treatment

It is a complex process involving many chemical and physical phenomenon that use consumable electrodes to supply ions into the wastewater. In the process, the coagulant is generated in situ by electrolytic oxidation of Fe and Al electrode as an anode material which produces ions continuously in the system. The released ions neutralize the charges of the particles and thereby initiate coagulation. These ions may remove the undesirable contaminants (metal hydroxide and metal phosphate flocs generated within the effluent) either by chemical reaction and precipitation or by causing the colloidal materials to coalesce and are then removed.

Chemical Precipitation

Chemical precipitation in water and wastewater treatment is the change in form of materials dissolved in water into solid particles. Chemical precipitation is used to remove ionic constituents from water by the addition of counter-ions to reduce the solubility. It is used primarily for the removal of metallic cations, but also for removal of anions such as fluoride, cyanide, and phosphate, as well as organic molecules such as the precipitation of phenols and aromatic amines by enzymes and detergents and oily emulsions by barium chloride.


Ultrafiltration (UF) is a variety of membrane filtration in which forces like pressure or concentration gradients lead to a separation through a semipermeable membrane. Suspended solids and solutes of high molecular weight are retained in the so-called retentate, while water and low molecular weight solutes pass through the membrane in the permeate (filtrate).

Reverse Osmosis

Reverse osmosis (RO) is a water purification technology that uses a semipermeable membrane to remove ions, molecules and larger particles from drinking water. In reverse osmosis, an applied pressure is used to overcome osmotic pressure, that is driven by chemical potential differences of the solvent, a thermodynamic parameter.

Self-Contained System – Turn Key Performance and Financing

Operating energy facilities, contemplating expansions and/or grass-roots facilities should consider contracting with Wastewater OEMs offering design, build, construction and on-site operation maintenance contracts.

These contracts, typically, reflect the following components:

OEM Self-Financing

OEM Reuse and Recycling of Treated Wastewater

Fixed Monthly Fees

Autonomous Operation incorporating AI technology enabling the Ability to react quickly to changes in feed-water and output requirements 

Such an approach avoids the lengthy and intrusive applications for industrial discharge permits and the associated public hearings. Opting for Reuse Recycle enable the energy facility to expand while ameliorating the regulatory [public media] concerns.


Shale Oil and Shale Gas

Hydraulic Fracturing uses millions of gallons of water per day; generating industrial wastewater in the form of flow-back and production waters. These wastewaters may be hauled away to disposal sites i.e. deep wells. “Disposal costs run $1.50 to $2 a barrel and transportation costs to disposal sites can add up to $4 a barrel,” Freeman said. “Recycling flowback water at the drill site can address both of these costs and make reuse a viable economic option.”

Haul water off-site for disposal over the 20 year life of a hydraulic fracturing well-project, it was estimated to cost $160 million (includes trucking costs, water). The costs for hauling away wastewater for deep-well injection ranges between $3 and $7 per barrel ($0.35 to $0.85 per cubic metre). For a newly fraced well, the cost could reach $100,000 for transporting over 14,000 barrels (1,670 m3) of flowback – water levels produced from each basin, and indeed, each wellhead can vary. Plus, an additional potential 3400 barrels (405 cubic metres) each day of transported produced wastewater, at $20,000 per day.

Apache estimates that treating flowback water costs about $0.29 per barrel. By contrast, disposing of water with a third party costs Apache $2.50. Apache has experimented with a freshwater alternative about a year ago and has so far managed to drill 50 fresh waterless wells, and it aims to drill a total of 70 by the end of this year. Success of this technology could produce huge rewards for the water-starved Texas oil fields, which are still suffering from the effects of a severe drought in 2011. Apart from reducing dependence on local freshwater supplies, Apache is also benefiting immensely from the reduced costs at fracking wells. A well typically uses 5 million gallons of water for fracking. So, this could result in a potential savings of around $350,000 per fracking well. This initiative has saved Apache an estimated $17.5 million already and could result in a total savings of $24.5 million by the end of this year. Apache has identified 3,293 drilling locations in the Wolfcamp Shale and the Cline Shale in the Permian basin. Using this new technique in all these locations could translate into a total cost savings upwards of $1.15 billion for Apache in the long term.

Well service providers are offering reuse and recycle as a part of their product line. Using Halliburton's H2OForward recycling service on some of its wells in New Mexico has led to cost savings between $70,000 and $100,000 per well, while no reduction in output has been noticed, The North American produced water treatment market is the world’s largest. Equipment sales for equipment used to treat wastewater from fracking operations as well as conventional wells


The Horizontal Drilling and Hydraulic Drillers have reduced operating costs – enabling incorporation of Reuse Recycle without sacrificing margins. Since 2013, the average wellhead break-even price (BEP) for key shale plays has decreased from $80/bbl to $35/bbl. This represents a decrease of over 55%, on average. The wellhead BEP decreased across all key shale plays, with Permian Midland experiencing the largest decrease, falling by over 60% from $98/bbl in 2013 to $38/bbl in 2016 (for horizontal wells only). Due to a higher average royalty, different decline profile and hydrocarbon split, Eagle Ford experienced one of the highest wellhead BEP among the main shale oil plays in 2016.

Per the International Energy Agency (IEA), “fracking could by viable with tough regulation, and only if companies agreed to use the latest technologies to avoid environmental damage – a move that would increase operational costs by 7%.” Say increase by 15% for O&M and another 25% for contractor Overhead & Profit so a reasonable estimate for Turnkey Reuse Recycle  on-site system with performance guarantees and fixed annual costs would be 9.8% ~10% - additional operating costs. This 10% increase can be accommodated for hydraulic fracturing systems due to oil [WTI] exceeding $60/bbl and for CCGT due to Natural Gas [Shale] cost below$3/MMBTU – without affected profitability and expected earnings.

Based on Cabot Oil & Gas 2013 estimated shale gas well cost ranging from $ 1.26 – 1.60/Mcf, on a $MMBTU basis Cabot’s shale well cost ranges from $1.22 – 1.54 /MMBTU. At spot price of Natural Gas of about $3/MMBTU Cabot is making enough profit to afford a 10% increase to contract with an OEM to install a complete Reuse Recycle facility. Cabot Oil & Gas first quarter 2018 Total Operating Expenses of $ 1.58/Mcfe [$1.52/MMBTU] confirms that based on Shale Gas spot price = $3/MMBTU sufficient margin remains after deducting 10% for expected increase to Operating Expenses from a complete wastewater Reuse Recycle facility.

Natural Gas-Fired Power Plants

Reuse Recycle of industrial wastewaters from Combined Cycle Gas Turbine power plants increase annual operating costs by 0.1%. But, power plant cooling water imposes considerable raw water demand. Reduction of raw water cooling water addresses plant siting issues in drought [e.g. California] and arid [e.g. Saudi Arabia] regions. Use of dry-cooling lessens raw water demand while imposing a 1% - 2% earning decrease. A 2% earning cut can be tolerated to a CCGT plant burning fuel – 50% operating cost contributor – based on Shale Gas priced at under $3/MMBTU. In 2008 Natural Gas cost about $12/MMBTU but due to HD+HF Shale Gas spot cost = $3/MMBTU – amounting to a 75% drop of fuel cost or almost 40% operating cost cut.

Natural Gas-fired power plants use millions of gallons of water per day. Recycling reuse of this water reduces new plant [i.e. Combined Cycle Gas-Turbine] these raw water demands.

For a 500 MW gas-fired, combined-cycle plant (typical of new plants in California) the use of dry cooling reduces the annual plant water requirements by approximately 2,000 to 2,500 acre-feet per year depending on the climate at the plant location. Implementing such cooling water recycle by a potential annual revenue reduction of about $1.5 to $3.0 million (1% to 2% of total)

The cost of dry cooling can be expressed an “effective cost” of water. This is defined as the additional cost of using dry cooling expressed on an annualized basis, divided by the annual reduction in water requirement achieved through the use of dry cooling. This “effective cost” of saved water ranges from $3.40 to $6.00 per 1,000 gallons. This compares to more typical costs for industrial and residential uses ranging from $1.00 to $2.50 per 1,000 gallons. The water savings achieved from the use of dry cooling vary from site to site and depend on the choice of source water. The site to site differences are due primarily to the differences in the water requirements for the wet cooling system and vary from 2,495 acre-feet per year at the desert site to 2,021 acre-feet per year at the mountain site.

Water requirements for alternate water sources are higher than for fresh water for two reasons. First, the wet cooling tower can be operated at higher cycles of concentration with fresh water make-up, thus reducing the blowdown flow. In addition, the alternate water sources must be treated prior to use and a wastewater discharge stream is created, which adds to the make-up requirements. The water saving with the alternate water sources vary from 3,143 acre-feet per year at the desert site to 2,546 acre-feet per year at the mountain site. It is important to understand that these costs and penalties are calculated for dry cooling systems which were sized using an optimization criterion of minimum total annualized cost based on current estimates of capital, fuel, and electricity costs. Other optimization criteria could have been chosen and would have yielded different results. For example, if a very high value were assigned to meeting peak power demands on the hotter days, a larger and more expensive cooling system would have been selected. While the total annualized cost would have been higher, the “hot day capacity reduction” would have been reduced or eliminated.



The International Energy Agency (IEA) said that fracking could by viable with tough regulation, and only if companies agreed to use the latest technologies to avoid environmental damage – a move that would increase operational costs by 7%. Say increase by 15% for O&M and another 25% for contractor Overhead & Profit so a reasonable estimate for Turnkey Reuse Recycle on-site system with performance guarantees and fixed annual costs would be 9.8% ~10% - additional operating costs. This 10% increase can be accommodated for hydraulic fracturing systems due to oil [WTI] exceeding $60/bbl. For new Natural Gas-fired Power Plants Combined Cycle Gas-Turbine [CCGT] promoted by Shale Gas the increased plant capital cost would be approximately $8 million to $27 million, or about 5% to 15% of the total plant cost. Similar to a 10% cost increase to Hydraulic Fracturing facilities this approximate 5 – 15% additional cost also could be incorporated at a spot Natural Gas price below$3/MMBTU – without affected profitability and expected earnings.


Energy firms should consider developing Requests For Proposals [RFPs] for Reuse Recycle of industrial wastewaters Turn-Key On-Site Autonomous Service Contracts and a Bidders List of publicly traded firms with the technical and financial capabilities to participate. Incorporating Reuse Recycle in new energy facilities [horizontal drilling – hydraulic fracturing, Natural Gas-fired Power Plants] promotes their acceptance in arid regions [e.g. Middle East] and while disparaging bans.

Dr. Richard W. Goodwin Environmental & Energy Consulting Engineer


Buecker, B.; “Wastewater Treatment Issues for Combined Cycle Plants”; Power Engineering; 04/14/2014

Cabot Oil and Gas Transcript Investment 4/29/18 Cabot Oil & Gas' (COG) CEO Dan Dinges on Q1 2018 Results - Earnings Call Transcript Apr. 27, 2018 2:29 PM ET

Goodwin, R.W.; “Environmental Perspective Update: Hydraulic Fracturing”; Pollution Engineering; Oct.2014, pgs. 34-38

Goodwin, R.W.; Neufeld, R.D.; “Emerging Energy/Environmental Trends and the Engineer” ; American Society of Civil Engineers; New York, N.Y. 1983; (ISBN:0‑87262‑380‑7).

Hincks, T. et. al.; “Oklahoma’s induced seismicity strongly linked to wastewater injection depth”; SCIENCE; March 16, 2018, vol. 359 pgs. 1251-1255

Maulbetsch, J. and DiFilippo M.; “Cost and Value of Water Use at Combined-Cycle Power Plants; California Energy Commission Public Interest Energy Research Program”; April 2006 CEC-500-2006-034

National Research Council 2012. Per ‘Executive Summary’: “Induced Seismicity Potential in Energy Technologies”

Patton, M.; “Recycled produced water cuts disposal costs”; World Oil; March 2018; pg. 27




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Thank Richard for the Post!
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