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6th Annual Low Cost Produced Water Management Marcellus and Utica 2016

March 30-31, 2016 - Pittsburgh, Pennsylvania

DAY 1

Comparing Case Studies and Case Water Treatment Technologies for Re-Use & Disposal, with

an Integrated Focus On Water Sharing to Generate New Revenue Streams in A CostConstrained Environment

1. CHAIR’S OPENING REMARKS

Ian Cameron, Consulting Engineer, Regen Innovative Technologies

 A key question to answer during the conference is how to reuse Marcellus wastewater 

in Utica wells.

2. KEYNOTE 1: MARCELLUS WATER MANAGEMENT PROGRAM 

Hear How Marcellus Operators Are Reconfiguring Their Treatment-For-Reuse and 

Treatment-For-Disposal Strategy to Manage the Changing Pace of the Industry

Marshall Roberts, Director of CONVEY Water Systems, CONSOL Energy

 CONSOL Energy: vehicle for water related technologies and champion of the reuse 

of mine water

 Market Cap= $2.7 billion and 2015 Total Revenue = $3.1billion

 The key question is what to do with all of the water and how to reduce capital

 Asset managers do not believe that water costs are that high

 Water management should always be less than 10% of the total cost of the well. Our 

goal is also to reuse 90% of water. 

 In 2015- 2016: Gas production increased by 10% and water also increased by 72%. 

Everyone started reuse initiatives, and then everyone put the wells on a hold. With 

limited reuse, water just fills up storage. 

 Water has been CONSOL’s biggest liability: found new initiatives with CSSD 

standards: maximized water recycling and developed a ground water protection plan. 

Started focusing on closed loop drilling and well casing designs. Closely monitor 

groundwater and disposal. 

 Water Chemistry is the determining factor in ability to reuse water

 General consensus is that Sulfates must be < 100 ppm for reuse

 100% reuse achieved by using Marcellus water in Marcellus well

 CONSOL considers Flowback to be 0 to 60 days, believe this is the general 

consensus

 Suggests that operators should put pressure on treatment vendors to achieve reuse 

chemistry

- Produced water contains barium

- Sulfates must be <100 ppm. This number is debatable. Other operators have done 

it differently. 
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- Barium sulfates inhibit well production

 Marcellus Shale

- 100% Reuse achieved

- Marcellus to Marcellus only

- Switch from anionic to cationic FR. 

 Utica Shale

- 80% reuse achieved. Haven’t been able to put 100% Marcellus into Utica yet. 

- Utica to Utica only

- Cationic FR only

 Flow back process

o 0- 60 days in the well is flowback water. After that the water follows the same 

delineation curve as the well. 

o Associated with process not water type

o Process allows well to flow back fluids, sand, and solids

o Prior to the well flowing hydrocarbons

o All flowback water is produced water

 Produced water

- All water that is returned to the surface through a well borehole

- Composed of frac water as well as natural formation water

- Follows similar production curves as gas

- Water quality and quantity vary by play

 Reuse

- Reuse in low activity period

- Marcellus water is able to be used for reuse:

Low TSS after initial flow back (~ 160 ppm)

Centralized impoundment storage

AST storage

Piped or trucked to pads

 Benefits:

- Reduction in volume of wastewater and reduced truck traffic 

- Less freshwater needed for fracturing 

- Reduced costs to operators

 Treatment

- Safety, environmentally compliant, and economic feasibility

- Sock filtration, settling ponds, thermal distillation, reverse osmosis, chemical/ 

electro precipitation

- Haven’t had the need to treat pre pad because it is cheaper to dispose via disposal 

wells than to treat.

 Disadvantages:

- Expensive pilot studies

- Early majority benefit most

- Little incentive

- Marketplace partnerships
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 Operator Partnering

- Sharing produced water:

Sharing agreements in place

Provide produced water to reduce disposal

Accept produced water to reduced fresh water needs

Assist other operators to help manage their tank and CI levels

- Asset Collaboration:

Reduce truck traffic

Reduces capital

Increases storage capacity

Grow industry network. 

3. KEYNOTE 2: UTICA WATER MANAGEMENT STRATEGY 

Hear How a Utica Operator Is Reconfiguring Its Water Management Strategy in The 

Context of the Low Price Environment

Eddy Biehl, President & CEO, Stone Bridge Operating

 Biggest concern: how do we manage water use, reuse, recycling and disposal when 

we don’t have any money?

 Safety is very important; it is a dangerous industry

 The industry experiences cycles of booms and bust, but can’t let that impact safety

 As a small operator, Stone Bridge has had to be creative with water management and 

reuse

- Water storage is extremely important, but there are challenges in winter weather 

areas. Winterizing the facilities such as heating the plumbing, moving the product 

and adding chemicals to lower freezing point, costs money. 

- Tanks are getting cheaper but still can run up quite a tab in a cashless 

environment. 

- In-ground impoundments - a tricky issue and on the way out for all but fresh 

water. 

 All of these issues add to the cost of operation

 Coordinated use is the key: 

- Continuous but reduced pace operations in- house

- Alternative uses inside the company

- Shared use between companies

 Induced seismicity could be a concern from a regulatory perspective (over-regulation)

 The industry is cyclical – Play Driven, Technology, Price, Political, and MacroEconomic (Booms and Busts)

1. Play-driven booms: examples are spindle top on the Texas gulf coast and the 

original Drake well at Titusville among many others. 

2. Technology-driven booms: engineering advances and geological advances

3. Price-Driven booms: local factors and global economy
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4. Politically driven booms: regional actions, government actions. 

5. Macro-Economic (Booms and Busts): recessions and booms, monetary policy and 

the like. 

 These five types of booms have happened and will likely happen again – it’s all a 

cycle: Horizontal shale boom was a result of all five factors

 We should learn from the past to help predict the future

 Talked about how the company accounted for water types and proximity to injection 

wells to create its water reuse plan. 

 Store it until we need it 

 Slowed tempo of operations and more careful about when completions/recompletions are being planned and costs of operations in general

 In ground impoundments: limited availability

 Tanks are expensive, especially when idle for long periods between jobs. 

 How we coordinate their use is the key

 Alternative uses in the company: displacing fluids into other wells to help control 

environmental and safety exposure

 Reduced pace operations can be a solution

 Try to figure out alternate use between companies

 Added problem of moving product in the winter: producing wells don’t recognize the 

change in weather and continue to give up water even when we don’t need it

 Induced seismicity: a lot of appointees are coming through with emphasis on 

Oklahoma events and northeast Texas events. 

 Earthquake map: Youngstown area: to date only few wells are monitored

 Epicenters are located away from injection well sites

 Bust right now: very unpredictable at times

 Play driven, technology, price, political and macro-economic types of oil booms 

determine if we will be in a boom or bust

 Play driven booms can impact locally

 Technology booms: rotary drilling in 20th century

 Geological advances: seismic in all its evolution and revolutions. 2D or 3D seismic

 Price driven booms: local vs. global factor. Interstate prices in the mid-70s led to 

drilling booms for Texas and Ohio for “self- help gas”. Supply shortages can drive 

global economy

 We had elements of all five factors 

 Prices hit all-time highs

 Be careful of what we are injecting into and what we’re doing for disposal operations. 

Diffuse disposal operations rather than concentrate them. 

 Think of material balance concept: looks for ways to reduce transportation costs

 Using fluids other than water: no water is good; we just need to improve the ways we 

are using it 

 Straight gas and nitrogen fracs to reduce column of water but it’s expensive. Vertical 

wells cost money. 
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4. WATER TREATMENT: POST-BREAK BREFING

Treatment of Produced Water for Reuse or Discharge: North American Case Study 

Lnsp "Naggs" Nagghappan, Senior Business Developer, Oil & Gas, Veolia Water 

Technologies

 Veolia: The only company in the world able to cover the entire range of 

environmental solutions. $30.3 billion and 174,000 employees. 

 Minimize truck traffic and carbon emissions

 Can we make freshwater out of this wastewater?

 We aren’t drilling or frac experts, we are just trying to get the impurities out of the 

water and make it more cost- effective. 

 600 trucks of produced water we receive in a day; handling the variability is a 

challenge as well

 Oxidation for post treatment: predominantly to remove benzene, 90% by MBBR. To 

get to less than 10 ppm. Use ultra violet radiation and hydrogen peroxide

 At 60,000 barrels a day. We are doing an on-site landfill for radioactive salt. 

 Client needs: 

- Minimize dependency on deep wells

- Cost-effective solution for treatment of produced water to discharge quality

- Robust technology to treat produced water highly variable in quality (30,000 ppm 

to 300,000 ppm)

- A reliable solution with high availability and long-term certainty

- Reduce truck traffic and carbon emissions

- Ability to recover valuable resources from produced water

- A commercial solution that will minimize long-term risk

- Wanted a 97- 98% uptime availability 

 Treatment technologies

- Necessity for Gathering & Equalization: 600 trucks/day unloading the feed water 

for treatment. High variability in feed water with field-wide truck deliveries.

- Necessity for Pretreatment: To control scaling issues due to specific ions in feed 

water, to control fouling issues due to oil and solids, to control corrosion issues 

due to specific ions in feed water.

- Necessity for Thermal Technology: High feed water TDS - need for 

crystallization solution, necessity to achieve Zero Liquid Waste to minimize 

disposal costs

- Necessity for Post Treatment: High concentration of dissolved gases in feed water 

(ammonia, benzene, VOC’s)

- Residuals Management: Large quantities of sludge and salt - offsite vs. onsite 

landfill. 

 Bench-scale Validation
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- Confirmed Treatment Efficiency: High quality treated water meeting target 

specification

- Validated Operating Costs: Chemicals and power demand, sludge and salt 

generation

- Validated the Ability to Produce By-Product Salts: Sodium chloride and calcium 

chloride characterization

- Validated Scaling and Corrosion Characteristics: Identified pretreatment 

contaminant removal requirements

- Determined Solids Settling Characteristics: Optimum sizing of clarification and 

dewatering equipment

 Treatment Approach: 

 Pretreatment:

- Goals are truck unloading and ion removal 

- 600 trucks/day are monitored at the unloading facility. 

- Equalization: manage influent variability and flow variations

- Clarification: particulates removal using solids-contact reactor clarification 

technology. 

- System is fully covered and gas blanketed to prevent emissions

 Crystallization:

- Process goal is the removal of dissolved solids - Removal of dissolved solids and 

zero Liquid Waste treatment objective

- CoLD® Crystallization Technology: Operates at low temperature, deep vacuum 

and mixed salts generation suitable for onsite landfill, Ability to recover byproducts (NaCl, CaCl2), Effective desalination of produced water

- Key Benefit: Lower OPEX costs than conventional approach, no calcium removal 

ahead of the crystallizer, Requires less pretreatment than conventional approach, 

Less sludge generation than conventional approach.

 Post- Treatment:

- Process Goal: Ammonia, benzene, VOC’s and solids removal, Neutral, buffered 

effluent.

- AnoxKaldnes® MBBR Technology: Hybas® biofilm technology, VOC, 

Nitrification, De-nitrification, Ammonia removal. 
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- Actiflo® Technology: High-rate clarification, Ballast flocculation technology, 

Suspended solids removal

- Advanced Oxidation: UV H2O2 Chemistry, OH radical based oxidation and 

Benzene removal

- Key Benefit: No liquid waste, low OPEX costs, Make treated water suitable for 

discharge. 

 Benefits: Treatment for discharge quality

- Reliable and Economical Solution with “High Certainty”

- Minimizes Dependency on Deep Well Injection and Associated Costs

- Reduces Truck Traffic for Disposal and Carbon Emissions

- Enhances Trucking Logistics with Location Central to Acreage

- Minimizes Fresh Water Withdrawal from State Waterways

- Ability to Recover Resources from Produced Water (fresh water, salt)

- An Environmentally Sound and Sustainable Solution.

5. NETWORKING BREAK SPONSOR’S COMMENTS

Designated Inter and Intra Jurisdiction Discussion Areas for Making Water Sharing a

Reality Across Eastern Pennsylvania, West Virginia, Ohio

James Milleson, CEO, OhioAcres4u

 Looks at the golden triangle as repurpose, reuse, recycle water

 Represent land and mineral industry- represent and educate the farmers and land 

owners

 Presentation not provided

6. MAKING A CASE FOR WATER SHARING

Water Sharing: Assessing How E&Ps Can Coordinate Frac Jobs and Put Infrastructure 

in Place to Make Water Sharing a Reality and Deliver Cost Savings

Josh Adler, CEO, Source Water

 Sourcing, recycling, transporting, and disposing of water for energy production

 Help companies by reducing operating costs: hauling and disposal

 Help service companies to help sell what they are selling: win-win solution through 

efficiency

 Reduce cost with zero capital and negative overhead

 Operators choose to dispose of their produced water when their tanks are either full or 

overflowing, in hopes of preventing inevitable costs. Doesn’t matter when you do it,

because it is probably going to cost the same. It’s all about planning to optimize for 

the lowest price, then go when it’s needed

 Today price is always the same, but then think about (for example) why airports are 

participating in expedia and kayak? Why should trucks do it? It’s good for them -

short term fixed capacity “perishable inventory”- best solution is to maximize 
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utilization, not selling it for highest price. That’s what sourcewater does for 

marketplace. 

 Water should be disposed when it’s the cheapest to do so. Marketplaces such as 

sourcewater provide an inventory and low marginal costs, and are a way for 

customers to react to prices all at one time.

 Sourcewater is helpful in cutting water management costs such as trucking and

disposal, and also eliminating the fear of contract losses. 

 You don’t call all the airlines in making an optimal decision, you go on the internet 

and explore your options and optimize a decision given your criteria - in a few 

minutes. 

 Parallel comparison through internet is the best option these days. When all the 

buyers are in one place, it’s easier to market your products and give people an 

opportunity to explore their options. Use price to change demand through an online 

marketplace. 

 Give companies and treatment facilities an opportunity to sell their water, or market 

their technologies, or water disposal to sell. Companies who want water, or disposal 

wells that need to find water.

 Insure your supply chain against disruption and have a potential to get paid to sell 

reuse water. Hauling waters and disposal service companies should want to be on our 

website if their business goals are to maximize sales and find fair value for it. We 

provide the real supply and demand through marketplace. 

 Inter-operator recycling: especially in northeast PA, this is a big deal. If you can’t use 

your reuse water because you don’t have any more completions, where is the water 

going to go? Most efficient way is to go to marketplace and haul it to another 

company that needs completion: perks of better logistics and participating in the 

marketplace. 

 Bringing down cost structure means more wells for everybody. 

 Truck bidding marketplace: we let you send out bids for competitive prices every day. 

Potential to save money and provide business for truckers who might have had last 

minute cancellations that day. 

7. WATER SHARING: MULTI-STAKEHOLDER PANEL

Assessing Potential Opportunities, Hurdles, Legal Challenges and Presenting Solutions 

to Expedite Agreements Between Operators and Utilize the Market Place for Water 

Sharing

Moderator: Josh Adler, CEO, Source Water

Panelist: Peter Dorrins, President, Junex

Panelist: Chad Bruinooge, Integrated Operations Center Tech, Anadarko Petroleum

Panelist: Rick Hall, Senior HSE Representative, Anadarko Petroleum

Panelist: Olivia Desser, Production Engineer, Anadarko Petroleum
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 Intended Outcome at The End of the Panel: Practical Steps for Streamlining Efforts to

Make Water Sharing a Reality in 2016

1. Chad Bruinooge: eliminate wasted management time making phone calls to find out 

who has what, where, and how much. 

o Reduce disposal and completion costs by recycling produced water between 

nearby operators. Anadarko doesn’t have its own water management team to 

handle water logistics, and it’s time consuming to contact vendors. We see 

value in having one place to access markets.

o Automate competitive bidding. Trucking rates are down over 30%, so we are 

paying a lot more than last year. Costs add up quickly if you have 20- 40 

trucks at one time on the road. Marketplace provides us with an opportunity to 

reduce such costs. 

o We like to eliminate wasted take- or pay-contract costs

o We have 110-miles of fresh water pipeline, 7 pump stations with about 12,000 

Horsepower between all of them, and significant numbers of impoundments 

and tanks. Currently, we haven’t run the pump stations in over 2 years, and 

some of our infrastructure is somewhat stranded in our acreage. But it’d be 

good for the producers who don’t want to spend a lot of capital to put those 

kind of systems in to take advantage of our infrastructure. For our 

infrastructure to be active again, we need consumers who are willing to pay. 

o Management doesn’t want the water business to make profits, but we are open

to charging what it costs and a small utilization fee that it costs to access those 

facilities.

o Our trucking approved list shrunk by a lot last year. Anadarko is down to only 

4 vendors that are okay to use on daily basis. There is no competition because 

we need them all. We don’t try to punish them because we need them to keep 

the wells flowing and keep the tanks empty, so having access to more vendors 

is essential. From our position it is a lot easier to force the trucking companies 

to join marketplace, because if they want to make money, they have to do it. 

2. Olivia Desser

o We are down to using crystallization plant and our broker for water. We are 

not the only ones operating in northeast, and there are other operators using 

such third party broker systems. To avoid getting into contracts and securing 

our options, and get a good price with vendors while offsetting any additional 

costs: marketplace helps us lessen the burden and we are able to come up with 

a better argument. It’s like put your extra tickets on stub hub and they are not 

going to waste. 

 2015 PA Quick facts:

- 31MM bbl. Produced Water

- 90.6% recycled in new completions

- 8.12% SWD

- 1.26% to NPDES facility
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 500 wells needed in 2016 to sustain this produced water model

- 60,000 bbl. produced water per well

- Operator transfer agreements. 

- The table represents average dataset from 2,025 Anadarko samples taken 

between Q1 2014 and Q4 2015: 

o 2014 produced water handling:

- Frac: 1,530,321 bbl. (99%)

- 3

rd party recycling: 9,000 bbl. (1%)

o 2015 produced water handling:

- Frac: 455,340 bbl. (49%)

- 3

rd party recycling: 467,625 bbl. (51%)

o 2016 produced water handling:

- Frac: 90,250 bbl. (11%)

- 3

rd party recycling: 721,950 bbl. (89%)

o We have seen resistance by waste treatment facilities to accepting their 

contracts with such phrases in writing. 

o Make resource trading not about relationships but about what is best for the 

business. Instead of calling my “friends” to look for an outlet, I will only look 

at what’s best for Anadarko in terms of who is willing to help me pay the 

most. Sourcewater is a great resource, but to make it more successful we need 

more cooperation. 

o We have to have a legal agreement to protect us from all arrows that could hit 

us. Many operators have various views that their legal departments feel 

strongly about, and every risk is a high risk and should be talked about. 

Working through that and getting everyone on the same page to establish such 

agreements is not an easy task. There isn’t a master blanket that works for 

everyone, so it’s challenging. It’s easier to see through source water and stay 

eye to eye on establishing such agreements. 

o Transportation efficiencies: 

- Scheduling interface w/predictive analysis that is not a spreadsheet (Gray 

Matter)
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- Dispatch & form an “engine application” which is a smart enabled device, 

which means that trucking companies have tablets and smart phones and they 

are able to see and accept loads in real time without having to make phone 

calls. (Gray Matter)

- Reporting optimization w/handoff to vendors

- Emergency rail option (Ohio SWD)

o Long- term evaluation: 

- Thermal technology: Onsite vs centralized

- UIC potential

- Waste generation: Solids vs Slurry

- Transportation: Rail vs Trucking

- Capital expense vs Operating expense

o Treatment levels

- Level 1 – Minimal Treatment – Reuse: Total Suspended Solids Removal, TSS 

– Physical Chemical Treatment and/or Filtration

- Level 2 – Specific Ion Removal + TSS Removal - Reuse

Target removal of ions like Iron, Calcium, Barium, Strontium, MetalsPhysical Chemical Treatment

- Level 3 – Meet Discharge limits: Must remove Total Dissolved Solids and 

ammonia (all ions), Discharge typically less than 500 ppm TDS, Typically 

Accomplished through (depends on influent TDS)

- Pretreatment + Membrane

- Pretreatment + Membrane + Evaporation

- Pretreatment + Membrane + Evaporation/Crystallization

- Pretreatment + Crystallization

o Treatment levels

- Capital and Operating cost increase as influent brine concentration increases

- Larger the size the lower the cost/bbl. to treat

5000 bpd, 12,000 bpd, 30,000 bpd, Due to economies of scale (Capital and 

O&M)

- Technology dependent upon effluent disposal requirements and options, reuse

- and influent brine concentration

- Pretreatment requirements may vary with each option: Minimize TENORM 

effect

- ‘Clean’ effluent from each can meet discharge or reuse requirements

o Methods for Life Cycle ‘Cost’ Minimization

- Single Owner to Merchant to Consortium to blends of each

- Size does matter, the larger the facility the lower the lifecycle cost (estimated 

cost over 10 yrs. including capital recovery, disposal and all O&M cost)

5000 bpd – $11/bbl.

12,000 bpd - $9/bbl.

30,000 bpd - $6/bbl.

- Merchant facilities - sell excess capacity to offset investment
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- Location

- Minimize trucking cost near a large user of high purity water (power 

producer) – value of high purity water can be greater than $1/bbl.

- Reuse/Resale - By-products, salts, other liquid products – equate to several 

$/bbl.

- On-site landfill

- Solids disposal is the single largest operating cost Est $2.50/bbl. or more

- On-site landfill can reduce solids disposal cost by 50 to 70%

3. Peter Dorrins

o Q: We all like to work with companies that have comparable standards. Is the 

minimum standard thing already built in?

o Josh answered: source water lets you set standards. You can search by setting 

criteria or you can expand you research but our system is able to help you 

with that. Options are open. Everyone has same issues every time no matter 

which source you are on: when does your liability end and other guy’s 

liability starts. It’s risky but if you can’t take risks you shouldn’t be in the 

business at all.

o Q: are their ratings or performance reviews like amazon?

o We haven’t extensively developed that area yet but it is a good source that we 

plan on working at in the future.

o Q: truck bidding marketplace is a great idea but how has the buying been from 

the haulers?

o We just launched it. We are getting a lot of haulers calling in but we are 

hoping to have an improved interest. Wen haulers don’t know who the 

vendors are, they can’t be biased in terms of who is calling. They only enlist 

competitive prices. Pricing will be hourly and by per barrel. 

o Q: any hurdles in terms of accurate reporting and any legal issues?

o Generally, PA DEP wants to encourage water sharing between operators. 

Yeah sometimes things don’t get reported the right way e.g. the source of 

water, but as far as sharing goes, paper work is pretty straight forward and 

standard paper work

o Q: is there a mechanism to illustrate water quality?

o When you create a water source listing, you do a scan of water quality test 

report but its voluntary but you know people are going to bring it up at one 

point so you might as well be up- front about it.

o Q: what thoughts have been given to future and if the business goes down, 

what guarantee do we have that it won’t go back to the old days?

o Hopefully the demand will stay. Before it was out there and you just couldn’t 

find it but no we are hoping it will always stay. In 2012, when everything was 

ripping, we were told that Anadarko wasn’t to help anyone but that has 

changed now. We reach out to other operators and we care about what other 
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operators are doing. With younger folks in the industry, we have realized that 

working together is the way to go.

o Q: who will house the data of chemistry of water when it is moved from 

partner to partner? If water is taken and tested and if it is not what the data 

says, who is responsible?

o Whoever the lister of the source provides is responsible to hold data. We 

function like a matchmaker, contracts are set between the buyer and the seller 

though. 

8. MOBILE TREATMENT VS. CENTRALIZED PERMANENT STRUCTURE

Evaluating The Extent to Which Mobile Treatment Is the Most Cost-Effective Way of

Treatment Vs. Centralized Facilities for Different Water Chemistries and Production 

Rates

Mark Patton, VP Sales & Marketing, Hydrozonix

 Mobile vs. Central is not necessarily an either-or question; the two can work together

 A combination of these options can work for each individual operation; everyone has 

different needs

 Don’t necessarily need a lot of treatment depending on the use of the produced water

 Have to consider advantages and disadvantages of traditional centralized treatment 

and low cost mobile treatment

 Hydrozonix described their details of treatment 

 Hydrozonix uses real time testing and monitoring to check their system 

 Bacterial growth usually occurs after the extraction wastewater reaches the surface

 Different ways to look at it: depends on equipment capacity

 Relocatable asset, costs are higher. 

 Where are you concentrating your drilling? And are you moving a lot? Help decide 

what kinds of structure you want.

 An evolution in terms of what people want in terms of water quality, at one-point

people only used filtration but now we have coagulation, oxidation etc. question is 

what do we really need? 

 Aeration: 

o Iron is significantly reduced 

o Used in working tanks and ground surface tanks

o Use oxygen in the air to oxidize iron

o Phase 1: submersible or floating. Submersible is better for oxidation and solid 

control

o Phase 2: supplemental oxygen. If water quality is really poor, and aeration 

will take a long time, supplemental oxygen helps in getting better results 

quicker. 

o Phase 3: filtration: targets TSS, bacteria etc. pay attention to bag fits and filter 

quality. Look at TSS goals and micron size of the bag you are using. Take 
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pieces of filter cloth with a syringe and collect solids and do a simple field 

particle size filtration. It will tell you what micron size to use. Looking at 

turbidity goals once you know what micron to use. 

o Phase 4: oxidation. Sulfides and bacteria are targeted. Primarily run on ozone. 

Eliminates the need for scale inhibitors. If oxidizing the water, reducers get 

eliminated (if you are using a breaker)

o Typically, monitor tanks throughout the process. Use air as an oxidant and 

chloride from water. 

o We recirculate tanks and we don’t charge for that because we are not adding 

any additional chemicals. 

o We do a lot of real time testing to ensure the system is working. We wanted to 

remove the interference we see in produce water. Idea is we want to create 

certainty. We need to understand how water quality is changing over time. 

Have special sample pre procedures, such as field methods developed in 

conjunction with manufacturers of the equipment we use.

o Stage by stage testing for some clients to see how water quality is changing at 

every step

o We look at effluent and influent of the system and look at flow back for 

bacteria testing. It’s important to do a third part lab testing but also real time 

monitoring. 

o Centralized facilities have their advantages but with mobile facilities we don’t 

have to commit and can place tanks wherever you want to. 

o Regardless of what option you choose, make sure to incorporate real time 

testing. 

o Typically flow back we look at a target of less than 100. At a certain point in 

time, everything gets flushed out called flow back period: for bacteria, we 

don’t use PCR. With ATP it’s all living organisms, we haven’t seen good oil 

field PCR method yet. 

9. EVAPORATION CONSIDERATIONS

Reviewing A Common Problem of Evaporation Removing Precious Water in Frac Water 

Storage Applications

Ian Cameron, Consulting Engineer, Regen Innovative Technologies

 Problem: evaporation is a loss of fluid and we always see a loss of precious water too. 

 Mechanical lids are costly, inefficient and could create an unsafe situation

 Wind speed is only a mild 3 mph (5 km/hr.)

 Storage tank outside diameter is 160 feet (48.8m) and Capacity = 41,000 barrels (6,500 

m3) of fluid

 Loss of water due to evaporation is 209 barrels/day (33.3 m3 /day)

 10,558,212 btu/hr. is the energy lost in this environment in

keeping the water at a desired frac temperature of 68oF (20oC)
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The rate of evaporated water can be expressed as:

g = (25+19v) A(xs-x)

g is amount of evaporated water in kg/hr.

v is velocity of air above the water surface in m/s

A is water surface area in m2

xs is humidity ratio in saturated air at the same temp as the water surface

x is humidity ratio in air

 Cost and logistics required to maintain heat and fluid volumes are high: especially cold 

weather 

 The solution

- Heated water temp sustained at 114oF (45.5oC)

- Outside air temp of - 4oF (-20.0oC)

- Liquid covering stops evaporation within seconds

- Liquid product: easily applied in minutes with or without fluid preset in the 

container. It floats uniformly on top of the fluids and fluid levels are easily 

measured from outside the container w/ layer of covering as little as 0.01” 

(0.25mm). HydroShield is resilient in windy conditions. 

 Advantages

- Frac fluid friendly: Does not impact any the performance of the frac fluid 

chemistry.

- Significantly reduces Aerobic Bacteria: Reduces biocide requirements to maintain 

frac fluid compatibility and lessens concerns about injected fluids altering the 

reservoir fluid properties.

- Does not create a “confined space” environment between tank fluid top and below 

mechanical cover for improved safety

- No need to enter the tank thereby eliminating concerns of foot traffic causing the 

liner to be punctured or damaged

- Conforms to any shape of container or pit

- No waste product to be “trimmed off” for disposal that would be associated with 

that of a mechanical cover.

- No need to clean-after-use like a mechanical cover

- No residual moisture / mold with a mechanical cover resulting from evaporated 

H2O

- No on-site mixing costs

- If other fluids are added after this liquid cover is in place, they are simply pumped 

into the container and the cover “re-heals” itself within seconds after the agitation 

has stopped.

- No freeze/thaw concerns

 Results

- After only 2 hours of applying the new liquid covering
16

Evaporation was reduced by up to 95%

- Evaporation is influenced by: relative humidity ratio (air to water), wind speed, 

cross sectional area exposed

 Cost savings

- Savings due to just reduction of frac water loss: Evaporation of water is now only 

10 barrels/day (1.7 m3/day) 5% vs. 209 barrels/day (33.3 m3/day)

10. PANEL DISCUSSION & WORKSHOP LED BY ANADARKO PETROLEUM

How Are Operators Going to Sustain Production as Base Assets?

Olivia Desser, Production Engineer, Anadarko Petroleum

 Allocation of capital: base- sometimes gets a bad rep. we are able to deliver with 

efficiency and have been able to have a sound impact within last 5 years. 

 Water management strategies have drastically changed form year after year. 

 2014: 99% produced water was recycled in our own fracs. 

 2015: 49% was recycled at ours and 51% through 3rd party recycling and other brokers

 2016 projections: they want 89% of water to be recycled at 3rd part operators. 11% is one 

frac that they have on their plate

 Produced water is difficult because it has extremely high TDS and chlorides. For 

discharge, we are still left with concentrated brine and solids after treatment. 

 Risks: in 2015, PA waste data reports showed that 31MM barrels were handled and 90% 

found home in completion and 8% SWD facilities and 1.26% NPDES facilities. 

 For 2016 we need 500 well completions to sustain this produced water model. 

Chad Bruinooge, Integrated Operations Center Tech, Anadarko Petroleum

 Graph with frac focus data: count of wells with 2010- 2015 number of fracs per year. 

Red= average total of water used per frac in barrel. 39% decline between 2014- 2015. 

 DEP Waste report map: cumulative water production for 2015. “sinks”- true outlet to get 

rid of the water such as SWD and NPDES discharge facilities (circles). Number of fracs 

per county with 2010 on the bottom and 2015 at the top. PA is split in two regions 

(northeast and southwest). 

 Northeast: 55% decline in amount of fracs in 2014- 2015. Creates a problem because we 

produce 10 million barrels of production water per year. Only one sink is available for the 

entire northeast: a crystallization facility that has a capacity of 1.6 million barrels only. 

So the rest of it goes into a different operator’s frac. 

 Southwest: activity has remained pretty flat and increased over time. Easy access to 

sharing markets. Access is a luxury because NE looks at $20/ barrel. 

 We can control transport efficiencies. Used excel spreadsheets to accomplish dispatch. 

Partnered with grey matter solutions: digital manifest program: provides a scheduling 

program that’s not just a spreadsheet and made it easy to navigate. Able to send the 

schedule out to trucks and have them assign a truck to those loads without sending emails 

or phone calls. No paper handwriting, no wrong data. 
17

 After trucking vendors handle the load, final piece is the reporting optimization. After 

load is completed, it’s stored on the cloud and is pulled back on real time for analysis and 

streamlines billing process. 

 Emergency access to salt water disposal option in Ohio via railways. Now we can access 

those markets for much less than $20/barrel using the rail program.

 We have thermal technologies. Solids vs. slurry issue, what fits better with transportation 

avenues to accomplish goals? We want to incorporate rail vs. trucking debate. We want 

to include railroads they can move more tonnage for less

 Capital vs. operational expenses. We are being asked to spend less capital and spend 

more on the operating LOE side. 

Adam Locke, Director of Technology, Tetra Tech

 Need to minimize transportation: one of the solutions

 UIC wells: class 2 D wells. Around since 1974. We are about 180,000 wells deep now 

and 30,000 are class 2d

 We have about 300, most of them are in Ohio. 

 UIC wells are part of the development process. 

 Our UIC wells are not regional currently. We are looking at what can be done to permit 

them closer to where the water is being generated. 

 Ohio DNR has primacy for permitting so does WV and PA. 

 PA: we have most of them in western but we are generating most water in eastern side. 

Only 2 wells are commercial and only 1 is active. We have formations in PA that are 

injection and we don’t have easy to target blanket formations. 

 Oriskany trend in PA: map shows green areas where it is fractured. Reservoir map so 

there are areas that are depleted. 

 Case study: bear lake properties: brine disposal wells. They were converted and they are 

depleted medina gas well field. They have up to 20 more wells that can be converted as 

well. 

 How to find a well? Look at the geological data. Drilling depth, don’t water out existing 

formations, injectivity testing is generally recommended to establish injection pressures, 

1k- 2k barrels per day are possible.

 PA requires a more surgical approach for siting injection wells than other states: 300,000 

improperly abandoned wells

 Regionalized thermal treatment: Anadarko (Feb. 2016). They wanted to see if thermal 

treatment would work in a mobile fashion. They brought a company from OK to run a 

submerged combustion thermal evaporator for testing. 120 barrels a day unit was used for 

demos. It comes down to thermal efficiency. 1000 barrels a day regionalized system 

makes more sense. They run right below saturation. Solids end up in a roll of, you don’t 

want steam coming off: that’s a potential loss. 

 Submerged combustion: the blower kicks on, you need air, ignition. Combustion gasses 

are injected in the vapor column and adjust the feed pumps and gravity flow is pretty 

typical. 
18

 We’re generating a lot of waste: pretty dry waste. 87% solids no water. Barium is very 

high.

 Permitting: DEP is very supportive. It was given the oil and gas division and it’s 

permitted by rule. We need gas, so permit by rule on pad. 

 40- 45$ per barrel. Take it by rail to Ohio and get the average cost down. 

Chip Cagle, Manager, Business Development, Commercial, Veolia North America

 Treatment levels

 Level 1: minimal treatment/ reuse: remove suspended solids with filters. If you are 

going to reuse in the pad or frac

 Level 2: remove iron, or metals, physical chemical treatment, TSS removal; more 

expensive

 Level 3: meet discharge limits: external site. Progresses from pretreatments needed at 

each head of the membrane, membrane evaporation, evap + crystallization etc. 

 Costs increase with influent brine concentration

 Larger the size the lower the cost/bbl. to treat

 Technology depends on type of effluent requirements. 

 How to minimize costs: produce water, truck loading, pretreatment, selective ion 

removal etc.

o Single owner to merchant facility partners

o Location: minimize trucking cost, find allocation near power plants so you can 

sell it to them

o Reuse/ resale: by products etc.

o On site landfill: can reduce solid handling costs. 

David Cercone, Project Manager, U.S Department of Energy

 Water research websites

 To find papers on treatment technologies and formations etc., NETL.DOE.GOV, 

RPSEA.ORG.

 Looking for step changes on how America uses and generates energy. 

11. THE SOLUTION TO DEEP WELL INJECTION AND ITS INDUCED 

SEISMICITY

Assessing A Patented Multi-Effect Evaporation & Crystallization Process

Brian Kalt, President, Fairmont Brine Processing

 Fairmont Brine has a patented multi- effect evaporation crystallization process that is able 

to process 5,000 barrels per day. 

 It doesn’t cost $6 per barrel and it doesn’t cost 50 million dollars to construct one.

 Charging between $5.50 - 8/bbl. and think they can reduce that

 Played video from their website: 
19

- currently frac water producer in Ohio, PA, and WV have only two choices: 1. Deliver 

their brine to Ohio, PA or WV for deep well injection or 2. Deliver their brine to a 

concentrator that evaporates much of the brine into distilled water leaving behind heavily 

salted brine which is then deep injected into an underground well. 

- brine is treated through a series of processes. Consists of three main operations: 

pretreatment, evaporation, and crystallization. 

- pretreatment: after arrival and before unloading, the contents of tracks are sampled and 

tested for chemical composition and physical properties. The truck is then unloaded into a 

large basin. The brine water is processed to chemically remove barium, calcium, 

strontium, metals, organics, suspended and gravitationally removed solids. Residual oils 

and solids are removed next and the water then moves to a large retention pond for 

temporary storage. 

- Evaporation: the brine water is pumped through heat exchangers to preheat the water 

and then to the deaerator to release the non- condensable gases (oxygen and nitrogen) 

before the evaporators. In the vapor liquid separators (VLS), brine water is concentrated 

as distilled water is evaporated out the top of a vessel. The condensed water vapors are 

free of salt and suitable for reuse or discharge to a river under permit. 

- Crystallization: occurs in the evaporation vessels as the water is evaporated and the 

concentration of the remaining brine exceeds the saturation point of the brine water

solution. The salt crystals are then pumped to a hydro cyclone to sort the smaller from the 

larger crystals. While the smaller crystals are returned to the VLS to continue growing 

and larger salt crystals are sent to a centrifuge for dewatering and then fed to a rotating 

weir before being conveyed to a storage pile to await customer distribution. 

- Potentially marketable product of the crystallization process are distilled water, 

crystallized salt and a liquid mixed salt solution consisting of calcium chloride and 

residual sodium chloride. Distilled water is used by driller as fresh frac water or it can be 

discharged as clean water. Crystallized sodium chloride is used as a supplement or 

substitute to rock salt. Liquid mixed salts is used on coal piles to keep them from 

freezing. 

 None of their products are landfilled or deep welled. 

 15 year sales and marketing contract with tetra technologies 

 TENORM is removed during pretreatment process, solidified, and sent to a landfill. 

 Send calcium chloride to IL for use at U.S. Steel in coal piles and in their process to keep 

rail carts from freezing up. Bulk of it also gets sent to Ohio on daily basis used for 

winterization efforts and to drill plugs out. 

 Sodium sulfate is used to precipitate radium and barium in their pretreatment. How much 

TENORM is precipitated into the sludge depends on the amount of barium in the 

incoming water. Water is received from Antero and TransEnergy and other local 

operators. If the barium levels are low radium passes to your plant, but barium levels can 

also be under the TENORM Value. In a 1:1 mole ratio for barium to radium sludge

generation is under140 micro rems an hour. If you’re 2 part of radium to 1-part barium 

coming in, you will have semi warm sludge. 
20

 Also adding a lime softening process to the plant that will remove magnesium. A gradeB calcium product is produced at their facility which is about 24% calcium chloride 

(ASTM grade is 28- 40 %). The grade B product ranges from $3- $7 per barrel depending 

on the calcium chloride concentration. It is not ASTM yet because some magnesium and 

iron is also found in it. Moving to a lime softening process to remove that. Currently 

generating about 2.5 tons of sludge a day on 5,000 barrels. About 8 tons with the lime 

softening process, so a total of 50 micro rems per hour. 

 Sodium sulfate is picked over barium sulfate as the precipitant because barium sulfate is 

extremely insoluble. So when you take it to landfill, it’s not migrating and it’s not going 

to end up in a leachate. 

 The reason we can charge $5.50- 8/bbl. is because we sell salt. The larger the plant the 

better the economics. 

 If we had a 60,000 barrels per day plant for a 170 million capital dollar cost, we would 

still have 21 full-time employees (currently the biggest expense). 

 Second biggest expense is natural gas. Consume 15,000 MCF/month of natural gas. The 

only product not sold is the barium radium sulfate sludge because it’s a landfill. 

 Discharge treated water; occasionally give it back to producer

 Planning to construct more CWTs closer to drilling centers to reduce trucking. If you’re 

within a 60-mile radius of a plant that could be in that $5-6/ bbl. range and it took you an 

hour to return an empty haul, you might take that $20/ bbl. price and get it down to $10. 

 Guaranteed unload time of 20 minutes and there is never any wait. 

 The cost for a 12,500 barrels per day plant is roughly 50 million dollars and our 60,000 

barrels per day plant design is just about 150 million dollars. They have the capital and a 

partner to help finance. 

 Have found that salt produced through their process is cleaner than salt normally used for 

road treatment; want to be able to locally produce road salt for the Northeast US. 

 Another reason to remove barium (other than to get rid of radium) is because barium 

chloride interferes with sodium chloride crystallization. On the calcium chloride side, it’s 

a matter of when you turn it into a dry vs. liquid product. We see that in our water, for 

every barrel we get about 50 lbs. of sodium and 16 lbs. of calcium. You want to monetize 

enough salt on per barrel basis. 

12. TENORM

Evaluating The PA's Technologically Enhanced Radioactive Material Study And Current 

Practices For Handling And Disposal of Waste

Jason Hubler, Senior Engineer, PA DEP

 TENORM Regulatory Framework

- Environmental Protection Agency (EPA)

- Nuclear Regulatory Commission (NRC)

- Dept. of Energy (DOE)

- Dept. of Labor - Occupational Safety & Health
21

- Administration (OSHA)

- Dept. of Transportation (DOT)

- States (e.g., Pennsylvania)

 The first, horizontal drilling, is one in which a vertical well is directed horizontally so 

that it penetrates a maximum number of vertical rock fractures

 The second is hydrofracing, a process in which portion of a well is sealed and water is 

pumped in. this produces pressure that fractures the surrounding rock to form a reservoir. 

 Up till 2015: a total of 9,031 gas wells were drilled. Between 2014 and 2015, 1,593 wells 

were built.

 PA DEP Required SW Radiation Monitoring in 2001, and the facility to have an ‘Action 

Plan.’

 TENORM: Technologically Enhanced Naturally Occurring Radioactive Material

- TENORM, a naturally occurring radioactive material not subject to regulation

under the laws of the Commonwealth of the atomic energy act of 1954, whose 

radionuclide concentrations or potential from human exposure have been 

increased above levels encountered in the natural state by human activities.

- NORM- Naturally Occurring Radioactive Material: NORM is a nuclide, which is 

radioactive in its natural physical state- that is, not man-made- but does not 

include source or special nuclear material.

 Background

- Generation of TENORM had increased significantly due to expansion in 

unconventional natural gas exploration 

- Issues that needed to be addressed included: potential worker radiation exposure, 

possible public radiation exposure, unknown environmental contamination, waste 

disposal. 

- Study began is 2013 and was completed in 2014. Final study report posted in

January 2015. 

 Site categories for sampling

- Well pads

- Wastewater treatment plants(WWTPs)

- Waste sludge loads to landfills

- Landfills

- Underground natural gas storage sites

- Gas fired electricity generating facilities

- Compressor stations

- Gas processing facility

- Beneficial use sites (e.g. Roads)

- Decommissioned well casings

 Sample types

- Solid samples (i.e., drill cuttings, muds, proppant, sludge, soils and sediment)

- Liquid samples (i.e., pre frac, flowback and produced water)

- Natural gas samples

- Radiation surveys (i.e., μR/h, direct surface dpm/100 cm^2
22

- ‘Smear’ samples for removable radioactivity

 Sample analysis

- The samples were analyzed for the presence of alpha, beta and gamma radiation 

(gross counting and spectroscopy)

- Some solid and liquid samples analyzed by XRF, ICP MS and neutron activation

- The gas was sampled for radon- 222 concentrations. 

 PA TENORM waste issues

- Oil and gas sludge, rock cutting

- Numerous sludge samples exceeded DOT criteria for Ra- 226 and Ra- 228

- Initial disposal RESRAD modeling performed c2002

- Additional c2004 MicroShield Calculations

- PA TENORM Study data has informed DEP for the need to update our approach 

for TENORM disposal

 Conclusions

- Well sites and pads have low worker exposure 

- O&G well frac and produced water high in Ra

- Potential for environmental impact with spills

- Unclear impact with the use of brines on roads

- Several wastewater treatment plants and environs require follow up for clean up

- ~25 % of TENORM sludge over DOT Class 7 limits

- Long term Ra in landfill leachate monitoring needed

- Sludge from wastewater treatment not in equilibrium between Ra 226 and Rn 222 

decay products

- O&G industry data on samples taken during DEP study in line with our data

- Landfill TENORM disposal protocols developed circa 2002 need to be re 

examined

- Follow up needed on ‘pigging’ and gas processing plants for potential worker Pb-

/Po 210 exposure

 New ND Regulations- 50 pCi/g
23

 Other notes from the speaker

- Doesn’t believe that conventional wells are being drilled in PA anymore 

- Radiation protection system

- Who’s handling the waste and what are we doing with it?

- Oil and gas well types

- Shale formation: problem starts with uranium series. In uranium formations it occurs 

unaltered. 4.47 billion years of half-lives to smaller than a few seconds long. 

- None of the isotopes from uranium – thorium are water soluble. Radium is the first 

soluble isotope. Radon 222 is the only gas and that has a special place. 

- PA DEP required all landfills to have radiation detectors and develop action plans for 

when alarms go off.

- TENORM , radioactive material that’s been altered in concentration by human activity. 

- NORM- the unhuman impacted version of radioactive material. We don’t see it in things 

like wastewater sludge

 Study: issues with O&G TENORM needed to be addressed 

 Issues included: waste disposal, unknown environmental impacts

 Developed a sampling plan and QAPP and identified labs for analysis. Conducted 

samples and report was prepared in 2014. 

 Result- report will be revised one more time. 

 Went to well pads, CWT, landfills, compressor stations, water treatment facilities, etc. for 

samples

 Samples collected in natural gas, liquids, solids, radiation surveys, UOG well, 

conventional wells, pipe recycling facilities, gas processing facilities, etc. 

 Samples were analyzed for the presence of alpha, beta, and gamma radiation

 Gases were sampled for radon-222 concentration (longer lived of the two radon)

 RESARD series of code: computer program that models to get to public dose limit. If 

you’re going to claim a property and live on that property. Found a number of samples

that exceeded the DOT criteria for total radium. The initial disposal model from 2012 is 

not adequate anymore. Need to reevaluate their approach of TENORM disposal. 

 CWT plants: no impact in indoor areas but contaminated sand in one of the facilities. Not 

a lot of exposure to truck drivers. 

 Landfills: no surface contamination issues

 Conclusions: more work needs to be done 

13. REUSING MARCELLUS WATER IN UTICA WELLS

Hearing How to Reduce Water Management Costs by Reusing Marcellus and The 

Practicality of Disposal in Utica Injection Wells

Yael Tucker, Research Scientist, U.S. Department of Energy, National Energy Technology Lab

 Marcellus produced water chemistry

- Calcium and sodium self- scale to produce calcite and halite
24

- High level of Ba, Sr, Ca as time progresses, may cause scaling within the 

infrastructure if fluids are reused without treatment. Low sulfate minimizes 

effects, if the same in Utica

- High levels increase toxicity of water

- Iron may create pyrite if hydrogen sulfide is present in formation

 Prediction based on the chemistry

- Scaling is a possibility. High salinity in Marcellus produced water is less likely to 

cause clays in Utica shale to swell than freshwater

- High levels of TDS produced fluids could cause plugging of pores in the 

formation

- Lower dissolved oxygen in produced fluids may minimize oxidizing reactions 

detrimental to steam or production

 Problems from biocide degradation

- Biocides degrade to more toxic and difficult to treat products

- Degradation products could be less efficient at microbial control and more toxic 

for transport and injection. 

- Studies have found that produced water contains sulfur reducing bacteria, acid 

producing bacteria and other organisms. 

- In Utica, it may be important to continue to consider the biological component 

 Marcellus vs. Utica- Biologically 

- Marcellus shale: depth of 5000 to 8000 feet. 

- 1.9 trillion cubic feet of natural gas and thought to be microbiologically sterile, 

but unlikely. 

- Utica shale: depth of 3- 7,000 feet.

- 38 trillion cubic feet of natural gas and about 940 million barrels of oil

- variety, petroleum rich areas. Variety of microbes. 

 Extracting DNA

- Which kit, how much water, how much rock, is there anything as too much?

 Microorganisms in Utica and Marcellus

1. Organisms found only in Marcellus:

 Deltaproteobacteria- includes sulfate- reducing bacteria

 Alphaproteobacteria- acid producing bacteria.

 Methanomicrobia- can produce methane.

2. Organisms found only in Utica and not Marcellus:

 Deinococcus spp. 

 Geobacillus stearothermophilus

 Paracoccus aminovorans

3. Although some organisms known to degrade petroleum are already found in 

Utica core: Pseudomonas, Flavobacteria, Vibrio, Actinobacter

4. Organisms from Marcellus shale could have detrimental effects on petroleum 

from Utica shales: Thermatogae

5. Same organisms may aid Enhanced Oil Recovery in Utica: Pseudomonas and 

Bacillus create several emulsifiers (Surfactin, rhamnolipid, lichenysin, 
25

Rhamnolipid, glycolipids). Bacillus creates biopolymers, Methanobacterium 

produces methane

 Potential benefits:

- Minimization of wastewater treatment

- Water preservation through reuse

- Less chance for clay swelling due to high salinity of Marcellus fluids

- Inoculation with beneficial organisms

 Potential problems:

- Degradation or inactivation of biocides before reuse

- Contamination of APB, SRB or oil degrading organisms

- Plugging of wells from high TDS

- Scaling from high Ba, Sr, Ca concentrations

 More notes from the speaker:

- Putting microbes from gas to petroleum areas. 

- Usually people overlook this part, sulfur reducing and acid producing bacteria

- Studies show that H2S producers can sour our gases. Halanaerobium and other 

alphaprotobacteria can produce acids

- Biocide degradation is a problem and they are degrading due to hydrolysis and 

photolysis. 

- Preferred sequencing methods to look for DNA in subsurface

- Getting live cells out of rock samples is very hard so sequencing is a better option than 

culture methods because we don’t know what these microbes need to grow

- Extract DNA out of cores or water using a kit to tell where microorganisms came from

- Relate the water in microbes to those in cores and water out

- We had about 61 different genera found both in rock and water and 4 in water in and 

water out alone

- Some microorganisms love dry conditions and radioactivity and they can survive in 

Marcellus shale.

- Methanogens are microorganisms that can produce methane. These organisms can be 

helped by giving them nutrients and then rely on them to produce methane at a faster rate.

- Some microorganisms grow really well in shale alone and fluids really help methanogens 

too. Some of the water to be disposed can be used to inject fluids

- Currently studying what nutrients are best for these methanogens. She analyzed one Utica

core and compared it to Marcellus to see how they differ

- Core came from dry gas Utica (WV), she found sulfur reducing bacteria that wasn’t 

found in Utica core, we are introducing sulfur reducing in Utica. Methanogens were only 

found in Marcellus. We are potentially putting methanogens in Utica as well and since 

the conditions are pretty similar they probably can make it. 

- These organisms are really good at making biofilms

- Radioactive species are found in Utica as well. 

- Carbon degraders can switch growth modes and can survive in harsh environments as 

well 
26

- Introducing Marcellus to petroleum producing Utica wells, we need to be concerned

about petroleum reducing bacteria. Carbon degraders already exist in Utica so we aren’t 

really making a difference. 

- Should fluids be recycled? These are positives to it but there are potential issues of 

introducing microorganisms from one scene to the other can cause problems

- We need to perform test to determine the efficacy of biocides to control injection of these 

microorganisms and address microbial issues faced by microorganisms. 

14. David Yoxtheimer, Hydrogeologist, Marcellus Center For Outreach & Research

Low Cost Produced Water Management Marcellus and Utica Shale 2016

Yael Tucker, Research Scientist, U.S. Department of Energy, National Energy Technology Lab

 Water use and brine generation

PA DATA:

- 1.5 million gallons per 1000 ft. of lateral

- 7 million gallons per well on average

- 7% returns out of the Marcellus based on DEPs number, 7.2 MMBBLs of flowback were 

generated

- 6.7 barrels for every million cubic feet of gas produced

- 4.6 trillion cubic feet of gas came out of Marcellus

 Shale fluid management options

1. Produced fluid management options

- Direct reuse (blending)

- On-site treatment w/reuse

- Off-site treatment w/reuse

- UIC well disposal

2. Recycling treatment technologies include

- Filter socks

- Chemical precipitation

- Electrocoagulation

- Filtration (micro, nano, ultra)

- Evaporation (MVR common)

- Costs of <$2 to $10+/BBL

3. Disposal technologies include

- Desalination with discharge

- Class IID UIC well injection

In Pennsylvania during 2015 a total of 38 MMBBLs of fluids generated

- 87.5% of shale gas return fluids recycled

- 6.4% disposed of via injection wells

- 4.5% treated to meet discharge standard

- 70% of fluids management for recycling occurring in the field

 Current Production
27

- 17 BCFD of Marcellus gas w/12.6 BCFD in PA

- Current estimate of 105,000 BBLs/D of produced fluids in PA

- In PA 87.5% recycled, 6.4% to Class IID wells, 4.5% to NPDES facility, balance in 

storage, landfills, transfer

- Disposing of ~6,600 BBLs/D of brine via UIC wells

- Currently require ~13 UIC wells capable of 500 BPD to dispose of brine in PA

 PA class IID disposal well locations

- 11 EPA-permitted Class IID UIC wells in PA w/ 5 permits in review

- 278,700 BPM of total capacity with 90,000 BPM of commercial capacity via 3 wells

- Most wells targeting depleted sandstone gas reservoirs (Oriskany, Medina, Elk Sands)

- Total 2014 unconventional brine injection in PA UIC wells was 157K BBLs (430 BPD)

- Nearly 95% of PA unconventional brine disposed of via OH wells

 Examples of injection- capacity Oriskany sandstone

- calcite-cemented quartzite to chert with variable primary and fracture porosity

- depleted conventional gas reservoir used for brine injection and gas storage

 Estimated Brine Injection Capacity (Volumetric)

- Using effective porosity of 4%, 50 feet of pay, and 40-ac injection zone area

- A typical injection well in the depleted Oriskany sandstone could ultimately 

accommodate an estimated 620,000 BBLs (~26 million gallons) of brine before 

filling available porosity

- Need to determine reservoir frac pressure to determine actual upper limit of 

injection

 WV Class IID Disposal Wells

- 46 active disposal wells

- 14 commercial disposal wells

- Target formations include: Oriskany, Newburg, Upper Devonian (Gordon, 

Gantz), Mississippian units

- Geology and injection rates similar to PA wells (estimated range of 100-1,000 

BPD)

 Utica-Pt. Pleasant Production in OH

- 2015 Summary of Ohio’s Utica and Point Pleasant Shale Production

- 1,246 producing wells (to date)

- 21.9 MMBBLs oil

- 954 BCF of gas produced

- 13.5 MMBBLs of brine produced

- 12.5 BBLs of brine/MMCF of gas (including BOE)

 Utica/Pt. Pleasant Shale Energy and Brine Production

- 3.6 BCF/D of gas

- 90 MBBLs/D of oil

- Current estimate of 37,000 BBLs/D of produced fluids (assuming 12.5 BBLs 

brine per MMCF gas)

 Class IID UIC Wells in Ohio

- 227 permitted with 215 operational Class IID wells in OH
28

- Estimated 31.2 MMBBLs injected in 2015

- Approximately 47% of injected fluids from out of state

- Average injection rate of 400 BPD/well

 Considerations for Class IID Siting and Use

- Finding suitable areas for projects, ideally away from residential areas yet near 

production

- Locating area with appropriate geologic setting with sufficient depth and 

permeability and lack of faulting

- Proper maintenance to ensure well integrity

- Permitting can take several years

- Public opposition

 More notes from the speaker

- Longer laterals = increased number of gallons used and produced

- Water use per foot: well lengths have increased over time. Water use stayed pretty steady 

- Relative volumes of frac water being used: more recycled water being used

- Shale fluid management option: depends on direct reuse/ on site or offsite or some sort of 

disposal, thermal capacity or use of disposal wells. 

- Disposal: desalination, NPDES discharge options, class 2D wells

- 87% of 28 million barrels were recycled and 6.4% disposed via injection wells and 4.5% 

treated to meet discharge standards

- 17 billion cubic feet of gas being produced in PA, a little over 100,000 barrels of fluids 

being generated. 

- Class 2d- disposal wells: 430 barrels per day.

- Disposal wells in WV: 46 total in WV 14 are commercial and estimated range of 100-

1000 barrels per day

- Projecting the Marcellus gas (WV and PA), 5.5 TCF

- 2015: 1246 producing wells in Ohio and 13.5 million barrels of brine

- 12.5 million barrels of brine/ MMCF of gas in Ohio. 

DAY 2

Evaluating Long Term Produced Water Disposal and Discharge, Regulatory Updates and

Compliance Strategies

1. CHAIR’S OPENING REMARKS

Ian Cameron, Consulting Engineer, Regen Innovative Technologies

 More collaboration as an industry

 Safety is a priority

 Costs for treating water varies as technology improves

 Coordination of resources will help the industry
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2. KEYNOTE PANEL: LONG TERM DISPOSAL & DISCHARGE STRATEG

Evaluating All Possible Options for Long Term Handling of Produced Water Whilst

Ensuring 24-Hour Water Supply, Sustaining Production Levels and Lowering LOE

Jide Famuagun, Vice President Production, Rice Energy

 Develop their own technology and work with operators

 Started working and developing a water application

 Developed a forecast on how much water they are going to produce depending in the next

5 years depending on activity

William Bates, Geologist, EPA

 93% of all wastewater was injected

 Don’t have a good handle on how the actual volume is being recycle or managed other 

than disposal wells

 Flex steel is the answer for corrosion free high quality pipes

Rob Wingo, Chief Operating Officer, Rice Energy

 Produce water lines to aggregate water to a central location for treatment

 Use whatever solution is best for where the pads are located

Jeremy Manno, Infrastructure Design Coordinator, Carizzo Oil & Gas

 Water chemistry affects the hydraulics of a system

 Stainless steel doesn’t mean anything, corrosion is always a problem

 High chlorides water will cause stainless steel to start cracking

 Meter the water going in and coming out to make sure there are no discrepancies

 Leak protection: periodic pressure testing is done to monitor it

 They have an app where you can scan barcodes on each tank and enter numbers from the

meter, also used for invoicing, prevents drivers from charging extra hours for just sitting

and not doing work- this takes all the guess work out of it.

 Carizzo uses a bar code system to track water from tank to tank

o Uses QR codes

o Records meter reading

o Invoicing is done through the system as well

 Ohio has more capacity for disposal than Pennsylvania. Second quarter last year, the

industry put away about 80,000 barrels a day. Ohio capacity could theoretically take care

of about 15,000 wells. Price is more expensive than Pennsylvania, but the capacity will

be there.

 Disposal is expensive

 Operators treat for solids, bacteria, and scale
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3. MITIGATING INDUCED SEISMICITY

Outlining Steps for Characterizing the Geology of Marcellus and Utica Formations Prior

to the Development of Salt Water Disposal Wells to Mitigate Induced Seismicity

William Bates, Geologist, EPA

 There has been an increase in seismic events: Increase in seismic activity due to 

injection wells and other human activities especially in Oklahoma. 

 3 components to injection induced seismicity: 

 Increase in formation pore pressure

 Optimally oriented for movement

 Need a pathway to allow pressure to get to the fault of concern

1. Pressure buildup: an increase in the formation pore pressure from disposal activities

2. Faults of concern: optimally oriented for movement and under critical stress, 

sufficient size for movement to potentially cause a significant earthquake; maybe a 

single fault or a zone of multiple faults and fractures. 

3. Pathway: a permeable avenue allowing the pore pressure increase to reach the fault.

 Kilometers away from injection site, you can still see seismic effects even years after 

injection stops

 Correlation between higher volumes and bigger earthquakes

 Looked at case studies, fundamentals of induced seismicity, explored petroleum injection 

methods to eliminate the interaction- report was completed in 2012

 Case studies were in OH, WV, AK, and ND: wanted to see what the state did and what 

else they could look at. “Minimizing and managing the potential for injections induced 

seismicity associated with class II disposal wells: a practical approach”

 Study was broken down into 5 steps:

1. Literature review and compilation

2. Analysis of four case examples

3. Development of decision model

4. Fundamentals of induced seismicity

5. Explore petroleum engineering methods

 Development of decision model: based on director’s discretion authority. Look at 

existing and new class 2 wells, look at the geologic seismic history, is there a concern for 

seismicity? Look at faults, pressure pores, pathways etc., if the concerns still remain, go 

through changes in monitoring and operational approaches to decide if a permit is to be 

assigned or if the potential can be eased or not. 

- Work flow and action plan: collect data such as volume and pressure numbers, 

perform GIS mapping and analysis, figure out if the potential can be reduced or 

its frequency: it’s not definitive that reducing something will reduce the risk, most 

importantly to not wait to have a 100% defensive proof to say these wells caused 

this event, we need a proactive approach
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- Multi- disciplinary site assessment: regional and local seismicity, detailed well 

information, geologic setting, reservoir characterization, reservoir pressure, flow 

character, pathway, and stress direction. 

 Petroleum engineering methods: quality of data is very important. More data= better 

evaluation. Looking at magnitude and frequency of events. Engage operators early for 

voluntary actions and to have more data. Modify operations if the need exists. 

- Two fundamental approaches: 1. Well testing: pressure transient or fall off testing 

can determine if a reservoir is fractured, as well as static formation pressure. 

Function of near well conditions. 2. Analysis of operational data: hall plots using 

operational data indicate changes in transmissivity at distance. Covers both near 

wellbore and distance increasing with time. 

 Buildup is usually directional and can extend miles. Important to have a contingency plan 

in the permits. 

 Take a proactive approach and engage operators and external expertise if warranted. 

4. DISPOSAL IN INJECTION WELLS

How Injection Wells Are Being Cost-Effectively Constructed, Implemented and Operated

Within State Regulations and Ensuring Seismic Events Are Mitigated

Moderator: Ian Cameron, Consulting Engineer, Regen Innovative Technologies

 All but 9 states have obtained primacies: where states handle most of the activities and 

conduct investigation and respond in terms of regulations. 

 Oklahoma is the most widely publicized: Agencies come together and discuss best 

practices. Oklahoma look at it regionally and they have developed regional plans in 

response to incidents where a plan may call in reductions or even shutting off some of 

these wells. 

 Texas passes some regulations to clarify what states can do in terms of terminating 

permit. 

 Ohio is the most crucial. North star well in Youngstown of 2011: 2 or 3 million dollar 

well. Seismic monitoring was about 150- 170 K. overall about half a million dollars in 

total. 

 Part of the new regulation package: no longer a one- step process. 1. Need a permit and 2. 

An order to build the facility in Ohio.

 Communities are engaging in the permitting and regulatory process

 Rex Energy: setup first set of networks and worked with regulators in OH.

 2013: second aftershock and last one correlated with the north star

 In 2013- 2014: seismic monitoring was continued to try to increase comfort with their 

operation.

 Oct. 2014: denial for permit to inject was issued and they got lawyers. Increasing the 

amount of produced water to be recycled and found that economics for disposal started to 

drop. Plugging the well in summer of 2016. 

o Location is crucial

o Audits: extensive audits on injection wells are crucial too

o Evaluations
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Kevin Coleman, Senior Counsel, Appalachian/Michigan Business Unit, Chevron North America

 Regulatory Overview: High level overview of federal, state, and local regulation of UIC 

wells and recent developments relating to induced seismicity

Derek Smith, Senior Director HSE, Rex Energy

 Youngstown was about a $4 mil well

Jeremy Sokol, Water Superintendent, Chevron North America

 Start evaluations with a google search: look for law suits etc. for companies

 Look at the capacity and its cleanliness. Do they have operational discipline?

 Are they in front of regulations? 

 Are they interacting with the community?

 Are they able to handle a disruption? What are the economics like?

 Do a geologic review of the facility 

 CSSD: if you’re a net consumer of water; you must reuse 90%. There is a difference 

between net consumer and net producer. 

Amanda Fernley, Environmental and Regulatory - Water Resources, Antero Resources

 Liability risk associated with injection

 A company’s largest risk is their regulatory risk

 There are regulatory risks with disposal wells

 Communities are starting to engage in permitting associated with injection wells

 Many regulatory risks that operators are willing to take on. 

5. WV AND OHIO WATER MANAGEMENT - PERMITTING COMPLIANCE

Overviewing Regulatory Agencies and Permit Requirements to Remain Compliant with

WV and Ohio Regulations

Amanda Fernley, Environmental and Regulatory - Water Resources, Antero Resources

 Water management needs to be done with a holistic approach: planning and permitting 

must conduct a roust, holistic evaluation of short- term and long- term solutions based 

upon anticipated operations. 

 Open communication with regulators can really help the permitting process

 Permits are often an afterthought – permit approvals and preparation take time

 Permit preparation can take up to 6 months, and then another 6-12 months for approval

 Federal, State, and Local regulators are involved in large-scale infrastructure projects

 Must identify appropriate consultations and permits for the operation
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 Local stakeholders are likely to communicate with each other; so open communication is 

important to be consistent 

 Holistic evaluation to water management. Tunnel vision by only looking at water

sourcing or disposal methods. No, we need to look at symbiotic relationships.

 Regular and open communication with regulatory agencies is crucial in getting permit

approvals

 Long time associated with permit approvals and permit preparation etc. process has no 

define time frame can take 6- 12 months. Preparation can take 6 months for each 

company for a thorough application.

 Federal: 

1. US. EPA: region 3- NPDES- important to communicate with EPA representatives 

to develop limitations. 

2. US Army corps of engineers- nationwide permits (general permits), section 10 

consultation (in a region of navigable water), consent for easement (flow of 

easement)

3. US Fish and wildlife service- section 7 consultation 

4. Ohio River valley water sanitation- mini inter state agency, no jurisdiction in 

enforcements but get resources for guidance. 

5. National Historic Preservation Act: section 106 Consultation

 West Virginia:

West Virginia Department of Environmental Protection

1. Office of Oil and Gas: 

- Centralized pit/ impoundment permit

- Associated pit/ impoundment permit

- Water management plans

- Class II underground injection wells

2. Division of Water and Waste

- 401 certification

- Individual NPDES

- Water Use Reporting

- Multi- Sector Industrial Storm Water General Permit

- Aboveground Storage Tank Act

- Construction storm water general permit

3. Department of air quality

- Rule 13 permit

West Virginia Department of Natural Resources

4. Office of Land and Streams

- Right of entry permit

West Virginia Department of Transportation

5. Division of Highways

- MM- 109 Entrance permit

- MM- 109 Crossing permit

- Upgrade/ improvement agreement

 As of Jan 1- 2016, large quantity users= 100,000-gallon limit

 US Fish and wildlife service now require monitoring while actively withdrawing. Group 

2 withdrawals.
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 Ohio:

o Department of transportation

o OH Department of Natural Resources: Division of water resources, Division of oil 

and gas resource

o OH Environmental Protection Agency: Division of air pollution control, division 

of materials and waste management, division of surface water

o Required to put water withdrawal sources but the operator of the fresh waters is

responsible for reporting that so produced water is not that big of a deal.

 West VA is pad plan based: required to define water that you’ll need for a full cycle of 

well pad including water needed for construction, drilling, reclamation etc.

 Ohio is distinctly per withdrawal source: focuses mainly on what you’re withdrawing and 

how you’re withdrawing and maintaining that 2 million gallons per day average over a 30 

day rolling time frame.

 Local Stakeholders:

o Watershed conservancy: stakeholder analysis

o Building code and fire marshals: constructing anything with cement, electrical is 

being brought, fencing etc. 

o floodplain management: development outside of flood plain as well

o Interbasin transfer: Chesapeake Bay, Lake Erie: regulatory inhibitions

o Local commissioners

 Planning and Permitting:

1. As part of its environmental impact analysis, each site is evaluated for a number 

of different criteria, including permitting evaluation for all federal, state, and local 

regulatory agencies

2. Based on the evaluation analysis, the chosen location is considered to be the most 

practical, safe, cost effective and environmentally sound solution to fulfill the 

required need.

3. Evaluation criteria: Environmental impact and community impact

4. Site location: minimizing environmental and community impact

6. STATE REGULATIONS

Hearing Updates from Regulatory Bodies for Marcellus and Utica On Regulations Will

Affect the Use of Surface Water for Disposal and Water Sourcing

Andrew Dehoff, Executive Director, SRBC

 Susquehanna River Basin Commission (SRBC’s) focus is on water sourcing, not disposal

 The Basin

o 27,510-square-mile watershed

o Comprises 43 percent of the Chesapeake Bay watershed

o 4.2 million population

o 60 percent forested
35

o 32,000+ miles of waterways

 The River

o 444 miles, largest tributary to the Chesapeake Bay

o Supplies 18 million gallons per minute to the Bay

o Supports Public Water Supply and Industry

 Federal interstate compact commission 

- Mission: provide for the planning, conservation, utilization, development, 

management and control of the water resources of the basin

- Commissioners, budget

- Technical staff

- Regulations, fees

 Issues facing the Susquehanna

- Water quality

- Water quantity: flooding, droughts, public water supply permitting

- 19% of streams impaired 8,400 miles out of a total of 49,000

 Stream Pollution Profile

- Agriculture: 3,800 miles or 8%

- Abandoned mile drainage: 2,000 miles or 4%

- Atmospheric deposition: 1,500 miles of 3%

- Urban runoff: 1,500 miles or 3%

- Other: 1%

 Assessment of Water Use Associated with Natural Gas Development – new report 

coming out

 Work cooperatively with three states to manage water quality

 Water sourced from multiple pads so developed methods to accommodate that

 Public scrutiny: to make public confident to ensure that water used was coming from

frack

 Criteria for renewing existing sources

- Similar criteria as a new source: demonstration of need. Administrative mechanism.

Authorization was needed to use water on the pad is an admin process and allows for

a quick turn- around.

- Historic usage: infrastructure, limitations. Recognize that there lots of demands for 

water, multiple companies targeting similar streams took out any road blocks for 

water sharing. Great benefit in allowing water to move back and forth and in sharing

- Subject to Dec. 2012 LFPP: new limits?

 Changes in rules

- Recently adopted water tracking methods

1. “CU at the source”

2. Daily gage report for tracking passbys

3. Improvements to post- hydrofrac reports

- Revised and simplified transfer rule

- New section defining minor modifications

- New section establishing process for general permits

 Tracking changes: to verify that we have a handle on tracking water and where it is going 

and what’s being done with it
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 Minor Modifications

- Correction of typos

- Changes to metering or monitoring conditions

- Adding sources for consumptive use

- Changing authorized water uses

- Changing schedules set forth in dockets

- Changes to intake designs

- Certain increases in total system limits

- Modifications to extraction well networks

 Transfer Rule- what are the changes?

- The requirement to submit NEW applications where the approval is older than 10 

years is removed

- The requirement that applications for grandfathered sources be submitted within 90 

days of the change in ownership is changed to be required as a condition of the 

transfer on a timeline approved by the executive director 

 Proposed Rule Changes

- FY17 fee schedule

- Policy: terminating review of applications

- Policy: expiring approvals

 Other notes from the speaker:

 Management initiatives

 Cumulative impact analysis

 Aquatic resource surveys

 Low flow protection policy: water withdrawal limits. Prohibition on taking water from 

stream once it hits a certain limit.

 Withdrawal limits

 Quantity of withdrawal relative to streamflow

 Use results of aquatic resource survey

 Regulatory incentives for using impaired water sources: reduced fees, quicker review, 

longer term

 Criteria for renewing existing sources: demonstration of need, historic usage and subject 

to December 2012 LFPP: London fall protection policy.

 Requirement to retain consumptive use approval on operable pads

 Revised and simplified transfer rule

 Established process for general permits- permits aren’t created but there’s a process for 

how one can be put in place. Request for pipelines? Short term use?

 Policy: encouraging use of dry cooling- for power plants that use natural gas. Reducing 5 

million gallons to only a few thousand gallons for review. 

 Minor modifications: issue permits but if changes in operations, we will authorize it 

following the minor modification process. 

 Propose rule changes

 Reduction to fees for new and renewing CU approvals

 Terminating review of applications- defining and formalizing existing procedures

 Expiring approvals- formalize process sequence: speak to the needs to submit an 

application prior to expiration. Send out notices ahead of expiration. 
37

 Public hearing (May 4) and comment period (May 16).

 Upcoming reports:

1. Assessment of water use associated with natural gas development: first 5 years 

2008- 2013, asses the trends where water is being sourced from. How has the 

progression of permits for fracking and drilling progressed with time? Assessing 

where the water source is occurring. No conclusions are drawn just making 

people aware. Charts containing administrative vs. technical violations.

2. Cumulative water use and availability study: very discreet. Water use approved 

vs. reported. On paper water that’s approved is a lot more than what’s reported to 

us. A publically accessible online map tool helps in developing statistics for water 

needed for aquatic ecosystems etc. 

7. WATER TRANSFER - AVOIDING RUPTURES

Evaluating Best Practices and Quality Control Procedures to Ensure E&Ps Are Pressure

Testing Transfer Lines and Guaranteeing There Is No Chance of Corruption and Spills

Eddy Biehl, President & CEO, Stone Bridge Operating

 Transfer Line applications:

- Pad to pad

- Storage (impoundment) to pad

- Pad to treatment/ disposal

- Disposal and treatment facility lines

 Types of Brine Transfer Lines:

- Temporary lines: lay flat, poly pipe: process and procedure dominate current

methods. Continuous metering of volume in and out. Regular static pressure testing

throughout the job, continuous monitoring and control of lines, pumps and facility,

double- wall systems are in development. Key elements for success: fluid

compatibility with pipe, pumps, manifolds and other equipment. Use of temporary

containment systems at connections. Standard procedures for each method and

training.

- Semi-permanent and permanent: HDPE or other plastic

- Steel

- Fiberglass

 Integrity Monitoring

- Construction design dominates current methods: corrosion is a key issue. Lines steel, 

fiberglass, poly pipe and reinforced poly- pipe are options. Double- wall or 

containment pipe is an emerging standard. 

- Design considerations: fluid composition and properties, now and through time. 

Pressure and volume requirements.

- Key elements for success: stabilize or treat fluid at input to system. Standard 

procedures for each method. 

 Double wall systems: 

o HDPE containment piping, reinforced poly- pipe transfer lines
38

o Advantages: readily available crews for installation. Competitive and inexpensive. 

Familiar to regulator and crews. 

o Disadvantages: limited sizes available for reinforced poly- pipe

 Integrity monitoring for double wall systems:

 Experience as contractors, operator, includes two systems

o Pressured air: difficult to seal systems, requires air compressors, tolerances are 

difficult to measure

o Unpressurized fluid detection: simple float sensor to detect fluid level. Require 

testing and monitoring of boxes, power and data communications can be supplied 

with parallel conduit. 

 2016 Oil and Gas Bust

- Most analysts think it takes around 800 rigs to meet long term demand

- Each week we set new record lows for the number of rigs working

- Drilling efficiency cannot make up for no rigs turning to the right

- No rigs= no wells= falling production (eventually)

- Natural gas prices are poised for a recovery, but it maybe next year

- The Appalachian Basin is the primary source of the oversupply of NG- Utica

- Especially the Marcellus are a huge new resource, drowning the market. 

- EIA projects a 25% increase in annual NG production over the next 25 years, nearly 

all from shale. That implies 800+ NG rigs, up from less than 200 today.