The Northeast ONG Marketplace - May 2015

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ENVIRONMENTAL MANAGEMENT- Page 14 West Virginia ASTs – Swimming Pools Not Included

ONG SPOTLIGHT - p 3 WATER MANAGEMENT - p 6-7 HEALTH & SAFETY - p 10-11

INDUSTRY INSIGHT - Pages 18-21

Recent Shale Oil and Gas Industry Ripple Effects

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The Northeast ONG Marketplace

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THE ONG SPOTLIGHT The Eastern Gas Compression Roundtable During the early 1970’s, it was common for members of the burgeoning gas industry to discuss the need for an education program that addressed operating and maintenance questions on engine/compressor systems. In the spirit of community, representatives from key companies that were operating natural gas compressors, along with product manufacturers, industry suppliers and delegates from West Virginia University came together to formulate a plan. With a mutual interest in promoting safety, innovation and education, a meeting was held on April 20, 1972 at the Lakeview Country Club in Morgantown, WV to develop an education solution. The group agreed that the formation of a Gas Compression Roundtable for the Eastern United States would address the needs of the local industry and provide a valuable resource for companies and their employees.

As a matter of procedure, the group became the General Committee for the formation of such an organization and adopted the name Eastern Gas Compression Roundtable. The General Committee concluded that the area to be serviced by the Roundtable would include principally that portion of the United States East of the Mississippi River and eastern Canada. The General Committee also voted that the Eastern Gas Compression Roundtable be hosted and held at West Virginia University.

The purpose of the Roundtable is to provide opportunities for persons in the gas compression and related industries to add to their knowledge of the operation and maintenance of compression units and related equipment. This conference has also been enhanced to offer learning opportunities for personnel in the areas of Engineering, Gas Control, Automation & Controls, Management and Environmental Health & Safety.

The first Roundtable was held May 16-18, 1973 on the Evansdale Campus of West Virginia University in cooperation with the College of Mineral Energy Resources.

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The “roundtable” discussion format was utilized with group discussions on eleven selected topics of interest. A member of the industry served as discussion leader in each session with manufacturing and/or service organization representatives serving as resource leaders. Attendance of 341 people representing more than 100 companies was recorded that first year.

Prior to the age of computers and online registration, the hundreds of applications to attend the dozens of training sessions presented a daunting task to coordinate.

Tickets for each class were printed and inserted into envelopes that were tacked to an easel board. Volunteers then took one application at a time and pulled class tickets from those envelopes, taking great care not to over or under fill any class.

Those who were involved at the time recollect that a suitable quantity of pitchers of beer were required to insure an attention to detail during the ticket pull. This yearly event became fun for all, cementing vendor/gas industry relationships that have lasted decades.

With this solid base to grow on, the Roundtable continued to expand over the years and began to include lectures and hands-on workshops as well as roundtable discussions to address the needs of the attendees. As participation continued to grow, it became increasingly more difficult to accommodate everyone on the campus of WVU and the decision was made in 1999 to move the EGCR to Robert Morris University in Moon Township, PA. The popularity and reputation on the Roundtable continued to grow over the years and refinements were continually made to the track programs and classes offered to address both entry-level and experienced station operators for the purpose of offering more specific training.

The tremendous growth opportunities brought on by the Marcellus and Utica Shale discoveries continue to feed the growth of the EGCR and the Board of Directors approved a move to the David Lawrence Convention Center in downtown Pittsburgh for 2015. From its humble beginnings in 1972 with a few hundred attendees and several roundtable discussions, the 2015 Roundtable will offer 97 unique class sessions in 12 specific tracks, as well as in-depth OEM training in 5 areas of interest and the Entry Level Compressor Station Operator Training Course.

The Eastern Gas Compression Roundtable offers a once-a-year opportunity to obtain some of the best training in the industry and an opportunity to network with others in the industry. We look forward to having you join us!

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The Northeast ONG Marketplace

ASSOCIATION MEETINGS WVONGA Spring Meeting | May 11 Wheeling, WV - www.addc.org

ADDC Region I Meeting | May 14-17, 2015 Wheeling, WV - www.addc.org

TOGA Annual Meeting | May 20-22, 2015 Gatlinburg, TN - www.tennoil.com

IPAA Mid-year Meeting | June 24-26, 2015 Sante Fe, NM - www.ipaa.org

VOGA Annual Meeting | June 24-26, 2015 Virginia Beach, VA - www.vaoilandgas.com

ARTICLES

ADVERTISER INDEX

THE ONG SPOTLIGHT: Eastern Gas Compression Roundtable.............................................................. 3

AIR/TAK................................................................ 11 ALBERTA RIG MATS.............................................. 4 ALPINE ELECTRIC............................................... 17 APPELLATION..................................................... 13 BENMIT.................................................................. 2 BRAD PENN LUBRICANTS................................. 11 BUCK’S FABRICATING........................................ 27 CALU.................................................................... 13 CHANCELLOR INSURANCE................................ 17 CPI SERVICE........................................................ 15 CST INDUSTRIES................................................ 12 D&S INDUSTRIAL PRODUCTS............................. 8 DIRECT RESULTS................................................ 16 ECOM................................................................... 13 ELECTRO-QUIP CORP........................................... 9 ENERTECH SOLUTIONS INC.............................. 23 ERNST SEED.......................................................... 3 ETC....................................................................... 11 FORTIS ENERGY.................................................... 7 HETRICK MFG, INC............................................. 13 JGX INDUSTRIES LLC......................................... 11 JH TOMBLIN FENCE CO...................................... 17 LEE REGER BUILD............................................... 11 LEE SUPPLY........................................................... 9 LYDEN OIL COMPANY......................................... 16 MACHINERY STREET............................................ 8 MID-ATLANTIC STORAGE.................................. 17 MJ PAINTING CONTRACTOR................................ 4 NORTH AMERICAN FIELD SERVICES................ 11 ONG ONE CALL................................................... 27 PERMA-FIX.......................................................... 12 PREMIER SAFETY & SERVICE INC.................... 26 PSB INDUSTRIES................................................ 13 RIG GRIP................................................................ 1 RIGMAIDS............................................................ 11

WATER MANAGEMENT: Renewable Water: Cleaning Flowback, Brine and Produced Well Water for Reuse, Discharge and Disposal....................... 6-7 HEALTH & SAFETY: Marcellus Well Monitoring Systems Provide Fast, Accurate Detection to Help Avoid Injuries, Fires and Explosions...................... 10 ENVIRONMENTAL MANAGEMENT: West Virginia ASTs – Swimming Pools Not Included .............. 14-15 INDUSTRY INSIGHT: Recent Shale Oil and Gas Industry Ripple Effects..................................... 18-21 NEW TECHNOLOGY: Electric, Natural-Gas Driven Units Power Well Stimulation........................... 24-25 LEGAL & FINANCE: Promoting Natural Gas in your Community........................................................... 26

CALENDARS ASSOCIATION MEETINGS.................................... 4 NETWORKING EVENTS...................................... 25 TRAINING & WORKSHOPS................................ 17 UPCOMING EVENTS........................................... 22

EVENTS DUG EAST ........................................................... 28 EGCR...................................................................... 2 NAPE.................................................................... 12 NACBMF.............................................................. 12

RIJA, INC.............................................................. 26 RJR SAFETY INC.................................................. 17 SHANNON SAFETY............................................. 13 STRAD OILFIELD SERVICES................................ 3 TANK CONNECTION.............................................. 5 UNIT LINER............................................................ 5 WEAVERTOWN ENVIRONMENTAL.................... 17

CONTACT US FOR ADVERTISING, INFORMATION OR MAILING LIST CHANGES:

The Northeast ONG Marketplace P. O. Box 1441 • Oak Hill, WV 25901 855-269-1188 Fax: 304-465-5065 E-mail: info@ongmarketplace.com

The Northeast ONG Marketplace will not be liable for any misprint in advertising copy which is not the fault of The Northeast ONG Marketplace. If a misprint should occur, the limits of our liability will be the amount charged for the advertisement.

We do not assume responsibility for the content of advertising or articles herein. Any warranties or representations made in the advertisements are those of the advertisers and not The Northeast ONG Marketplace. Any warranties, representations or opinions made in the advertisements or articles are those of the contributors and not The Northeast ONG Marketplace.

May 2015

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The Northeast ONG Marketplace

WATER MANAGEMENT

RENEWABLE WATER:CLEANING FLOWBACK, BRINE AND PRODUCED WELL WATER FOR REUSE, DISCHARGE AND DISPOSAL By: Timothy J. Drake, Ph.D. & Gerald P. Willnecker, Zinkan Enterprise, Inc. & Todd Ennenga, Purestream Services Oil & Gas Industry Challenge: Produced water is water trapped in underground formations that come to the surface during oil and gas exploration and production. It occurs naturally in formations where oil and gas are found and are millions of years old. When oil or gas is extracted, they’re brought to the surface along with this produced water as a combined fluid. The composition of this produced fluid includes a mixture of either liquid or gaseous hydrocarbons, produced water, dissolved or suspended solids, produced solids such as sand or silt, and recently injected fluids and additives that may have been placed in the formation as a result of exploration and production activities.

oxidizing chemicals and polymers, followed by an Induced Gas Floatation step to remove suspended solutions (IGF+) and a final cleanup step using Advanced Vapor Recompression (AVARA System). Overall the combination of WellREADY, IGF+ and AVARA (FIGURE 1) units provide a multi-stage economical and reliable solution for higher level treatment of produced and frac flowback water.

Deployed in the field and closer to the wellhead, these systems promote minimal liability for spills by providing clean, distilled water for piping and transfer around the field and reduce overall water handling costs. The WellREADY, IGF+, and AVARA are highly advanced energy efficient combined water treatment and brine concentration systems. These systems treat produced and frac flowback water and provide varying level effluent streams based on needs including distilled quality water and clean, concentrated brine for re-use in field operations.

How It Works: Produced or frac flow-back water (#1) enters the WellREADY (#2) treatment system where organics, metals and bacteria are oxidized and polymers added to coagulate the suspended solids. In addition heavy metals drop to the bottom of the system for collection and non-oxidizable petroleum materials float to the top for skimming. The stream moves to the IGF+ (#3) unit for minimal pretreatment. Air and gas is percolated through the material from within the main vessel to produce a stream of water and oil with fine bubbles. Oil and suspended solids create a floc in the presence of clarifier chemicals. This flocculent is removed (#4) from the surface in a froth skim system.

FIGURE 1: WellREADY, IGF+ and two AVARA units capable of treating 3000 BBL/ Day of produced water while yielding 2000 BBL of distilled fresh water.

The American Petroleum Institute reports that produced water handling and treatment represents an $18 billion cost to the oil and gas industry in the U.S. alone.

Anecdotal evidence suggests that the cost of the disposal of oil and gas produced water ranges from as low as $0.002 per gallon ($0.08/barrel) to as high as $0.30 a gallon ($12.00/barrel). By contrast, water for agricultural irrigation (USDA) can be as low as $0.0001 per gallon ($0.004/barrel) and municipal drinking water costs in the range of $0.001 per gallon ($0.04/barrel). The price of cleaning produced water is therefore as much as 300 times greater than municipal water, and as much as 3,000 times greater than agricultural irrigation water. The separation, handling, and disposal of produced water represent the single largest waste stream challenge facing the oil and gas production industry. As the United States moves toward greater energy independence, hydraulic fracturing for oil and natural gas will continue to increase along with the demand for water in these industries. In order to keep up with the demand for water and bring down overall costs there is a strong push for re-use of as much of the processed water as possible. Removing the impurities from flowback and produced water for re-use or disposal in an economical manner is crucial to continuing exploration and production in low resource pricing cycles. The ongoing need for brine in this industry will grow as it is used for controlling well pressures, capping, stabilizing drilling mud, and dissolving of downhole additives.

Cleaning Up Water: Many solutions exist to solving these issues which include chemical treatment, thermal evaporation and distillation and many other technologies. One such example is a multi-step process whereby an operator feeds their produce water through a chemical treatment step with WellREADY™

FIGURE 2: Overview flowchart of the WellREADY, IGF+ and AVARA Water Treatment Process.

De-oiled water exits through the bottom of the flotation unit and is piped to the AVARA System. Water in the AVARA core is heated and boiled (#8) in a patent pending thermally efficient vapor recompression process. Steam from (#8) process is re-condensed (#6) to provide clean, distilled water. Residual chlorides are concentrated to a (#7) brine of about 250,000 parts per million. This brine (#6) is clean and available for re-purposing or recycling back to oilfield for use. The distilled water stream can be reused, or repurposed to any use as normal fresh water.

Zinkan Enterprises is known for its reliable and innovative water treatment technology. This, combined with the company’s team of outstanding experts in oilfield water treatment, clearly sets their services apart from other technology and treatment companies. Zinkan’s water treatment team works closely with field operators to optimize AVARA system integration within existing field operations to provide clean, distilled water and a concentrated brine.

May 2015

Page 7 destroyed. The below chart shows an example output for the AVARA system. Note that the lower the Feed TDS the more efficient the system isat extracting fresh water volumes and concentrating remaining brines.

For additional information please contact the author at Zinkan Enterprises Inc., 1919 Case Parkway North, Twinsburg OH 44087, Phone 800-229-6801, www. zinkan.com.

FIGURE 3: Arial View Full AVARA System (Left), Field Deployed AVARA (Right – Back) & IGF+ (Right-Front)

When the various technologies used in the fully integrated system are employed to treat flowback or produced oil and gas well water a number of key advantages accrue to the end user company. These include the ability to efficiently recycle up to 75 % of said water with Total Dissolved Solids (TDS) of up to 150,000 ppm. The reuses include, replacing fresh water in any and all processes. Deriving a byproduct highweight clean brine (FIGURE 3) that is useable in place of other brines for drilling mud stabilizer, capping (killing) wells that await production infrastructure, and much-reduced true sludge volume that would be disposed in a downhole disposal well.

All of the above can significantly reduce the overall water costs of sourcewell processes and contribute to the savings accruing to additional future wells. The robustness of these systems allow handling of a variety FIGURE 4: Final Byproducts – Sludge, of feed water input quality.

Concentrated Brine, Clean Water One fully integrated system (Oxidizer, IGF, AVARA) can process 1500 barrels of flowback or produced water in a 24 hour day. It can produce over 1000 barrels of clean distilled water in that time. With available operating power the overall system output volume can be scaled in 1500 barrel increments because components are packaged in independent stand-alone modular formats.

Reduced operating costs are aided by innovative low pressure design which minimized system fouling issues experience with some competitive units. And last, but certainly not least, bottom-line-reducing energy efficiency, (system consumes only 3.5 kW per barrel processed) is achieved by employing mechanical vapor recompression distillation technology that continuously recovers and reuses the original boiling-point process thermal energy. This significantly cuts the overall operating budget needed to accomplish your environmentally friendly fracturing flowback and produced water remediation goal.

Overall, each AVARA System is designed to treat 1500 BBL of Flowback or Produced Water during each 24 hour period (TABLE 1). Table 1 outlines expected volume projections for typical production. The AVARA system has shown highly cost effective success in applications where the untreated flowback or produced water tests in the feed Total Dissolved Solids (TDS) range is between 50,000 and 150,000 ppm. A 50,000 Feed TDS with Brine, TDS of 200,000 will typically have a recoverable fresh water output of 75% of the input feed and microbes completely

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Each month, over 11,000 subscribers in the oil and gas industry receive this free business-to-business resource. Our mailing list is frequently updated using a variety or resources to maintain distribution to the most current industry professionals working throughout the region.

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Page 8

The Northeast ONG Marketplace

May 2015

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The Northeast ONG Marketplace

HEALTH & SAFETY

MARCELLUS WELL MONITORING SYSTEMS PROVIDE FAST, ACCURATE DETECTION TO HELP AVOID INJURIES, FIRES AND EXPLOSIONS By: Albert E. Ketler, PE, President When discussing health and safety, it’s important to talk about the personal protection equipment (PPE) and work habits of the individual workers at a site. It’s also important to talk about the equipment that protects the site itself.

For a third of a century Rel-Tek Corp of Monroeville, PA has pioneered in the design and manufacture of advanced gas detection sensors and systems, covering toxic and explosive hazards of underground coal mines, tunnels and gas/oil wells.

Rel-Tek’s Safety Technology Center is shown here.

Rel-Tek’s sensor designs employ low-energy techniques to permit Intrinsic Safety (IS) approvals to make life easier for the end user. The alternative explosion proof (XP) technology is just as safe as IS at the outset, but is far more costly to install and maintain.

Of course, low energy circuits require more engineering know-how, but the results are worth the effort,

enabling solar energy to support the monitoring and communication functions for remote well sites in the North.

A gas explosion can decimate a gas well investment, while risking lives of workers and neighbors. The WellBossTM system pictured has four IS combustible gas sensors on 80-ft cables. A 100W solar panel powers the unit, plus enough battery backup to fill the long time gaps between sunny days in the NE. A MagiKal® utility automatically calibrates the four sensors monthly, or anytime on command. This enables the WellBoss to provide precision gas detection for years on end, unattended. WiFi, radio and secure satellite antennas on the top rail transmit alarms and status off site, accessible anywhere via cell phone and Internet.

Wireless sensor links are available.

For Marcellus applications where winds mix and dilute gas leaks, the GasBoss® natural gas sensors have 10x greater sensitivity (0-10% LEL) than the normal (0100% LEL) for the industry. Also, in view of the many gas components of natural gas, the wide-spectrum capabilities of catalytic-bead technology are ideal for Marcellus wells where everything is possible. Competitors offering optical (NDIR) technology can read just one gas component, usually methane, and then overreact to the ethane content.

A gas well of note using NDIR sensors was reading 140% methane(?). Indeed, in the NDIR world, after calibrating with methane gas, just 1% ethane reads like 20% methane. The GasBoss® sensor, however, reads some 85 different combustibles – e.g. methane, ethane, propane, and even hydrogen -- as they actually contribute to the LEL. Optical sensors work fine on methane alone, but they over respond to the inevitable ethane, a phenomenon known for years and dubbed by the British “the ethane catastrophe.” Beware of readings of natural gas using NDIR sensors, as in natural gas environment containing ethane, they may be reading 20 times

higher than actual, also exaggerating the green- house gas contribution.

Did you know that NDIR sensors can’t detect hydrogen at all?

Gas pipelines require regular surveillance for gas leaks. A Rel-Tek truck is rigged with a high-sensitivity GasBoss® natural gas sensor. It can traverse long distances quickly, while logging gas levels for the maintenance team to follow.

Pipeline compressor stations involve a series of buildings to be outfitted with a variety of sensors, monitored continuously by Rel-Tek’s MillenniaDX® data acquisition systems. Sensors can include the usual CH4, CO, CO2, smoke, flame (UV & IR), H2S and NO2, and even level, pressure, temp, RH, noise, vibration, RPM and process variables.

Maintenance garages for repairing, testing and storing alt-fuel vehicles can be outfitted with our Millennia-DX gas detection systems, whether large or small.

Rel-Tek’s MultiGas-LDSTM, on-vehicle leak detection system, is ideal for meeting the new code requirements for monitoring leaks on an alt-fuel car, truck or offroad vehicle. Sensor temperature limits have been boosted to 180F (82C). A foursensor package with a cab-mounted “MG-LDSTM” control panel can be installed quickly. Of course, our automatic sensor calibration utility can be included.

For large buildings and garages, Rel-Tek has designed and produced gas detection systems for the alt-fuel industry for 20 years, having contributed to the present methods and guidelines used nationwide. Our largest project is NJ Transit’s Howell bus garage, a 5-acre building using 250 NG sensors. After 16 years, the system is still fully operational, and management is well pleased.

Our signature MagiKal®, automatic sensor calibration utility, is a standard RelTek® system feature, receiving rave reviews for significant labor savings (payback).

Another important project, the photo below shows one of six MagiKal® stations in use at WMATA (Washington, DC Metro Transit Authority.)

Rel-Tek engineers will review your facility and provide assessments for a CNG, LNG, and hydrogen gas detection system to comply with present standards, usually at no charge, if sketches are provided. A budgetary quote will also be provided for client’s consideration.

Call or email for additional information on the above products and services.

Rel-Tek® Corporation 4185-4189 Old William Penn Highway Monroeville, Pennsylvania, 15146, USA Phone 412-373-6700, 800-783-9228 sales@rel-tek.com www.rel-tek.com

May 2015

Page 11

Compressed Air and CNG Dryers – Refrig/Regen Jay K. Gault II National Sales Manager 107 W. Main St. Worthington, PA 16262 www.airtak.com jgault@airtak.com

PROVIDING QUALITY, COST EFFECTIVE DRILLING EQUIPMENT SOLUTIONS DRILL RIGS . TOP DRIVES . MUD & FRACKING PUMPS POWER GEN UNITS . DRILL PIPE . FITTINGS . BITS . PIPE TUBULARS Customer Service Gettysburg, PA 17325 . Phone: (717) 683 9518 Email: customerservice@jgxindustries.com Website: www.jgxindustries.com

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Page 12

The Northeast ONG Marketplace

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NORM/TENORM Engineering Perma-Fix Environmental Services offers expertise in radiological engineering for the Marcellus Shale and Utica Shale mining industry. We have a fifteen year history and proven track record providing expertise with naturally occurring radioactive material (NORM) and technologically enhanced naturally occurring radioactive material (TENORM). With an office in the center of the Marcellus and Utica Shale mining states, Perma-Fix is uniquely and strategically located to serve the mining industry.

Services Include: • Radiation protection awareness training • Management and consulting services • Equipment and tooling decontamination services • Radiation dosimetry programs • Exposure assessments • Gamma survey and sampling • Site characterization and waste characterization • Waste disposition support • Regulatory support For more information contact: Operations Business Center 2800 Solway Road Knoxville, TN 37931 Phone: (865) 690-0501 jbowers@perma-fix.com

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The Northeast ONG Marketplace

ENVIRONMENTAL MANAGEMENT

WEST VIRGINIA ASTs – SWIMMING POOLS NOT INCLUDED By: Melissa Pagen, Vice-President of Business Development, GreenHunter Water Black licorice aromas tickling the nostrils may conjure thoughts of childhood for many people, but for those of us in the oil and gas industry, it may conjure thoughts of West Virginia’s Elk River incident in 2013 and the AST regulation fervor to follow. Instead of revisiting the sensationalized elements, let’s focus on the aftermath. Although this industry already has a nearly arresting amount of government oversight at one level or another, the resulting tank bill is an impressive example of how governing systems were designed to work.

The goal of the AST Act was/is to protect water resources from above ground storage tanks that are in a position (contents, location, etc…) to have adverse effects in the event that the integrity of their structure, plumbing, containment, or any other element with impact, is compromised. The initial bill (SB 373) provided for such protection, but was the equivalent of driving in a nail with a sledgehammer. In fact, over 48,000 tanks would be regulated under the first bill. The WVDEP may have cringed as much as industry professionals at this prospect. Luckily, apathy is not one of the characteristics of people of industry. Industry representatives worked diligently to educate the public, regulators, and legislators to effectively help make the bill relevant. In the process, the public, the regulators, and the legislators have proven that the system can work and that the ‘powers that be’ are more effective than what centuries of satirists have depicted. This educational dialogue resulted in SB 423, which amended the AST Act, with significant improvements to focus on what the legislation was intended to do – protect water resources.

• This includes: o Mobile devices remaining in one location on a continuous basis for 365 or more days o Ancillary aboveground/underground pipes and dispensing systems up to first point of isolation • Expanded exemptions To clarify further, the following are not defined as ASTs (again, thank you Spilman Thomas & Battle): • certain regulated shipping containers and barges; • mobile tanks; • process vessels; • devices containing drinking water for human or animal consumption, surface water or groundwater, or food or food-grade materials for human or animal consumption; • devices located on a farm used exclusively for farm purposes (unless located within a zone of critical concern); • swimming pools; and • empty tanks held in inventory or offered for sale.

For those who want a more comprehensive legislative play-by-play, please see the following article on the Spilman Thomas & Battle website: http://www.spilmanlaw. com/resources/attorney-authored-articles/environmental/senate-bill-423amends-aboveground-storage-tank-ac, or…

SB 423 itself at: http://www.legis.state.wv.us/Bill_Text_HTML/2015_SESSIONS/ RS/Bills/SB423%20SUB1%20enr.htm For those who want to skip the juicy details and get the quick and dirty facts, the following is what you need to know, starting with an overview of important dates pertaining to the amended bill: • March 27th, 2015: Governor Tomblin of West Virginia signs SB 423 into law • June 12th, 2015: Effective date of the law • July 1st , 2015: All ASTs must be registered o -Tank in service before July 1st, 2015: $40 o -Tank in service on or after July 1st, 2015: $20 • (X/X/2016?) + 180 days: Evaluation complete and Certificate to Operate due (dependent on date that standards are established by WVDEP) First, is the burning question: What constitutes an AST? With gratitude to Spilman Thomas & Battle for boiling the definitions down, an AST is: • Device containing accumulation of >1320 gallons (≈32 bbls) … of fluids that are liquids at standard temperature/pressure • Constructed primarily of nonearthen materials, including concrete, steel, plastic or fiberglass reinforced plastic • More than 90% capacity above the surface of the ground

“Mobile Tank” and does NOT fall under the definition of AST, unless it stays in one location for 365 days. This type of tank does NOT even need to be registered.

What is a “…zone of critical concern?” you ask. .” It is one of the distinctions in what will be the most heavily regulated tanks. The term regulated AST contains two subcategories, “Level 1” and “Level 2.” “Level 1” tanks will be more regulated than “Level 2” tanks, as they pose a greater threat to water resources in the case of equipment failure or any incident that could lead to a breach.

“Level 1”: (1) ASTs located within a zone of critical concern (“ZCC”), source water protection area, public surface water influenced groundwater supply source area, or any other AST designated by WVDEP as a Level 1 tank; (2) ASTs that contain a “hazardous substance” under CERCLA, 42 U.S.C. § 9601(14), or identified on the United States Environmental Protection Agency’s “List of Lists” in a concentration of one percent or greater, regardless of the AST’s location, except that ASTs containing petroleum are not Level 1 tanks based solely upon containing constituents on these lists; or (3) ASTs with a capacity of 50,000 gallons (≈12,000 bbls) or more, regardless of contents or location.

May 2015

Page 15

“Level 2”: ASTs that do not otherwise qualify as a Level 1 AST but are located within a new zone of peripheral concern (“ZPC”) are in the subcategory Level 2. Although it has been determined that the ZPC will extend an additional 5 hours travel time upstream from a public water supply intake (beyond the perimeter of the ZCC), the actual area has not been designated. The WVDEP or the West Virginia Department of Health and Human Resources will be responsible for establishing this area. Once established, it may be safe to assume that the WVDEP will notify those who have tanks that fall within the ZPC. The phases of the rollout of the legislation/regulations are Registration, Evaluation, and Certification (Initial certification, then annual). Inspection, monitoring, and testing will then be evergreen and proceed according to protocols (to be set).

Registration is clear, definitions are fairly clear, and aside from a to-be-determined date, even certification is clear. Evaluation is where things get a little foggy. In order to evaluate, as mentioned, the WVDEP will establish a program with standards to oversee the following: • Tanks • Secondary Containment • Leak Detection • Recordkeeping • Maintenance and Corrosion Plans • Closure and Remediation • Fees • Certificate to Operate • Civil Penalty Assessment Process Once standards are established, the evaluation (and certification) of a regulated AST and its secondary containment structure must be done by one of the following within 180 days of the date those standards are effective: • a qualified registered professional engineer licensed in West Virginia • an American Petroleum Institute or Steel Tank Institute qualified inspector • a person holding certification under another program approved by WVDEP

If those tanks were located in WV, they would be defined as ASTs and would have to be registered, evaluated, and then certified.

Once the regulated tank and secondary containment has been evaluated and meets the yet-to-be-determined standards, the certification must be signed by one of the aforementioned three, or a person designated by the owner or operator.

Spill prevention and response plans (SPR) remain a requirement for regulated ASTs, but an owner or operator can certify that they are operating with an alternative plan in place (ex. Spill Prevention, Control and Countermeasure [SPCC]). The amended Act requires updates to such plans every five years.

Given that the standards/rules/protocols are still being determined, a certain amount of nail-biting and preparation for battle is justifiable. The impact of any law is most acutely felt because of the body of rules that implements the law in our daily lives. If the overhaul of the initial bill and the resultant amended bill, that proved a genuine interest in relevancy, is any indication of what can be expected of the upcoming standards, there is hope.

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INDUSTRY INSIGHT

RECENT SHALE OIL AND GAS INDUSTRY RIPPLE EFFECTS By: Rick Stouffer, Senior Energy Editor, Shale Energy Business Briefing Contribution By: Kristie Kubovic, Director of Communications, Shale Media Group Edited By: Mindy Gattner, Editor, Shale Media Group

The current status of the shale oil and gas industry has initiated numerous ripple effects within the industry—some positive and others negative. Every company is dealing with these effects in one way or another, whether by forging ahead and growing by acquiring other companies or cutting back through job losses and budget reductions.

One area, seemingly not affected by this wave, is the midstream sector and the pipelines. According to Bentek Energy’s recent Northeast Expansions Report, pipeline capacity expansions are coming online at a jaw-dropping pace. Between 2010 and 2013, there were 36 pipeline projects brought online in the Northeast totaling 8.94 Bcf/d in capacity. However, between 2014 and 2017, there are 52 pipeline projects – new-build and expansions – east of the Mississippi River slated to come online, totaling 35.82 Bcf/d in capacity.

At the recent Upstream PA 2015 conference, held on April 16 in State College, PA, the Atlantic Sunrise Project and Constitution Pipeline were discussed. For example, the approximate 124-mile Constitution Pipeline would be a major transmission pipeline project, connecting the abundant Appalachian natural gas supply in northern Pennsylvania to major northeastern markets.

“Pipelines benefit everyone. New England needs pipeline infrastructure – they’re at the end of the straw and there’s not enough gas at the end of that straw for them,” relayed George Stark, Director of External Affairs, Cabot Oil & Gas Corporation. “It’s crucial to get the Constitution Pipeline up north from Susquehanna, Pennsylvania, where Cabot is producing about 2 Bcf/d there.”

The project consists of compression and looping of the Transco Leidy line in Pennsylvania and various locations along its mainline between Pennsylvania and South Carolina, in addition to a new-construction pipeline segment, referred to as the Central Penn Line, connecting the northeastern Marcellus Shale play to the Transco mainline in southeastern Pennsylvania.

The new construction segment will be jointly owned by Transco and a third party.

Williams expects to place Atlantic Sunrise into service in the second half of 2017 as part of $4.8 billion in transmission projects planned to come online through 2017. Atlantic Sunrise adds to the list of Transco’s projects to connect supplies of domestic natural gas with demand on the Eastern Seaboard from New York City to the far Southeast.

Transco, the nation’s largest-volume interstate natural gas pipeline system, is a wholly owned subsidiary of Williams Partners, of which Williams owns roughly 60%, including the general-partner interest.

2. TransCanada’s North Montney Mainline Project Receives NEB Recommendation for Approval - Posted: 4/17/2015 TransCanada’s North Montney Mainline Project Receives NEB Recommendation for Approval Calgary-based TransCanada said Thursday, April 16, Canada’s National Energy Board has recommended the federal government approve the company’s proposed $1.7 billion North Montney Mainline pipeline project.

Here is a look at some of these recent ripple effects as they appeared in Shale Energy Business Briefing (SEBB) in around the past month. The midstream pipeline projects, mergers and acquisitions (M&A), and job losses below highlight that even in this industry downturn there are both positive and negative effects.

Positive Pipeline Projects (Top 4 Recent Pipeline Projects) 1. Williams Seeks FERC Approval for Atlantic Sunrise Pipeline Expansion Posted: 3/31/2015 Energy infrastructure company Williams said Tuesday, March 31, its Transco unit is seeking authorization from the Federal Energy Regulatory Commission (FERC) for its $2.1 billion Atlantic Sunrise expansion project.

The expansion would transport roughly 1.7 billion cubic feet per day of natural gas (Bcf/d) to markets in the Mid-Atlantic and Southeastern US. “Atlantic Sunrise is a vital piece of North American energy infrastructure needed to transport low-cost, abundant supplies of natural gas from the Marcellus producing region in Pennsylvania to hungry markets along the Atlantic Seaboard,” said Rory Miller, Senior Vice President of Williams Partners’ Atlantic-Gulf operating area.

“Shippers have signed long-term commitments for the expansion’s entire capacity … .”

“The project is a critical component in the infrastructure chain between prolific and growing Canadian gas supply and existing and new markets, and the NEB recommendation is a significant milestone for the growth of our NOVA Gas Transmission (NGTL) System,” said Russ Girling, CEO, TransCanada.

The North Montney project will provide new capacity on the NGTL System to meet the transportation requirements associated with increasing development of natural gas in the Montney Basin in northeast British Columbia, TransCanada said.

May 2015 The project will connect Montney and other Western Canadian Sedimentary Basin supply to both existing and new natural gas markets, notably emerging markets for liquefied natural gas (LNG).

The Mainline project, with initial capacity totaling 2.4 billion cubic feet per day (Bcf/d), will consist of two 42-inch pipeline sections, Aitken Creek and Kahta, totaling roughly 187 miles, and associated metering facilities, valve sites, and compression facilities.

The project will also include an interconnection with TransCanada’s proposed Prince Rupert Gas Transmission Project to provide natural gas supply to the proposed Pacific NorthWest LNG liquefaction and export facility near Prince Rupert, BC. NGTL expects to have the Aitken Creek section in service in 2016, and the Kahta section in service in 2017.

Progress Energy Canada, a subsidiary of Malaysia’s Petronas, has contracted for 2 Bcf/d of firm receipt service and 2.1 Bcf/d of firm delivery service. Other, unnamed producers have signed contracts for 78 million cubic feet/day (MMcf/d).

3. Kinder Morgan Contemplating Second Utopia Pipeline Project - Posted: 4/14/2015 Midstream giant Kinder Morgan is contemplating building a second pipeline to flow natural gas liquids from eastern Ohio’s Utica Shale play to Ontario, Canada.

The second pipeline is known as Utopia (“Utica to Ontario Pipeline Access”) West.

Kinder Morgan already has begun work on the $500 million, 240-mile Utopia East project, which will ship ethane and ethane-propane mixtures from Harrison County, Ohio, connect to Kinder’s existing Cochin Pipeline near Riga, MI, then to Windsor, Ontario.

Utopia East is expected to be in service in January 2018, offering an initial capacity of 50,000 barrels per day (BPD).

Kinder saw additional opportunities for a pipeline into which the Utopia systems will feed. Cochin is a 1,900-mile, 12-inch line that transports hydrocarbon liquids that crosses three Canadian provinces and seven states.

“We are recognizing we have some underutilized pipeline on Cochin on a project we’re calling Utopia West,” said Ron McClain, President of Kinder Morgan’s Pipelines Group, during the company’s recent analyst day conference.

Page 19 natural gas and natural gas liquids pipelines,” said Terry K Spencer, CEO, ONEOK Partners.

The project, to be built in phases, includes roughly 200 miles of new, 30-inch pipeline currently designed to transport up to 640 million cubic feet per day (MMcf/d) of natural gas with up to 570 MMcf/d to be transported to Mexico markets.

Agreements representing the initial design capacity have been executed with the Comisión Federal de Electricidad (CFE), Mexico’s national electric utility, and a subsidiary of Fermaca. All transportation agreements will be firm take-or-pay deals with a 25-year term.

Roadrunner was fully subscribed in its initial design through an open season held in December.

The pipeline’s initial phase for 170 MMcf/d of capacity is expected to be completed by the first quarter of 2016. The second phase, which will increase the pipeline’s capacity to 570 MMcf/d, is projected to be completed in the first quarter 2017.

The third and final phase of the project is expected to be completed in 2019 and will increase capacity to 640 MMcf/d. ONEOK will manage project construction and will be the pipeline operator upon completion.

“The signing of this joint venture agreement with ONEOK Partners is another key step in Fermaca’s plans to extend its network of gas pipelines across Mexico and into the US,” said Manuel Calvillo Alvarez, Chief Operating Officer, Fermaca.

Mergers and Acquisitions (Top 4 Recent M&A Deals) 1. Oil Major Royal Dutch Shell Offers $69 Billion for UK’s BG Group - Posted: 4/8/2015 Oil major Royal Dutch Shell has confirmed it is in advanced talks to buy UK energy supplier BG Group, in a $69 billion cash-and-stock offer.

The transaction would boost Shell’s growth in liquefied natural gas and deep-water exploration, the company said in a statement.

If the deal is consummated, BG Group shareholders will own roughly 19% of the combined company. Shell said there is a $1.12 billion cancellation fee if no agreement is reached.

The company is considering building Utopia West in parallel to Utopia East. “We think there would be large synergies on the cost of construction if you did them simultaneously,” McClain said. “But we won’t do that without committed shippers.

We’re working on that now and will probably have a lot of interest because of the cost of doing this simultaneously.”

Utopia West would ship up to 95,000 BPD of natural gasoline from the Utica and Marcellus Shale plays, according to Kinder Morgan.

4. ONEOK, Fermaca Building $450 Million-$500 Million West Texas-to-Mexico Natural Gas Pipeline - Posted: 4/2/2015 ONEOK Partners on Wednesday, April 1, said it’s entered into a 50-50 joint venture with a subsidiary of Mexico City-based natural gas infrastructure company Fermaca Infrastructure BV to construct a $450-$500 million pipeline from the Permian Basin to Mexico.

The Roadrunner Gas Transmission pipeline project extends from ONEOK Partners’ ONEOK WesTex Transmission natural gas pipeline system at Coyanosa in West Texas, west to a new international border-crossing connection near San Elizario, TX, where it will connect with Fermaca’s Tarahumara Gas Pipeline.

“We are pleased to partner with Fermaca on this strategic pipeline project and about the opportunity to add to our extensive 36,000-mile integrated network of

Oil prices have plunged roughly 50% since June due to the shale oil “boom” in the US and a decision by Saudi Arabia not to cut production -- creating an environment similar to the early 2000s when many super-mergers took place.

At that time, oil major BP acquired rivals Amoco and Arco, Exxon bought Mobil and Chevron merged with Texaco.

BG, which has ambitious production growth targets and multi-billion dollar projects in Brazil, East Africa, Australia, Kazakhstan, and Egypt, has long been

Page 20 seen as a rare potential acquisition target, including by cash-rich rivals such as Shell or Exxon.

Shell is one of the world’s largest energy producers, with a market value of about $192 billion. In addition to being a major oil producer, the Anglo-Dutch company is also among the world’s largest natural gas companies, with more than three trillion cubic feet (Tcf) of output in 2014, even though that represented a 4% drop from the year before.

The deal talks come after Shell scaled back its ambitions to become a major producer of shale gas.

Shell and its other big rivals have largely failed to benefit from the boom in the US after acquiring shale assets that turned out to be unprofitable.

Shell has been unloading some of those fields, as well as pulling back from shale development in Europe and China. A BG investment would refocus Shell’s gas operation on the big, offshore projects it has a history of developing profitably.

After Shell replaced only 26% of the oil and gas it pumped last year, the fastest way to acquire new resources may be an acquisition.

A purchase of BG would also give Shell access to the company’s highly prized offshore Brazilian oil assets, significant undeveloped gas resources in East Africa and a huge liquefied natural gas project in Australia that is ramping up this year.

Shell has been eager to get into East African gas projects, but it was outbid a few years ago and doesn’t have a big position in Brazil. BG’s liquefied natural gas shipping and marketing division may also fit well with Shell’s gas portfolio and LNG expertise.

2. C&J Energy Services, Nabors Industries Complete Merger Transaction Posted: 3/25/2015

The Northeast ONG Marketplace LRR Energy’s production totals roughly 40 million cubic feet-equivalent per day (MMcfe/d), increasing Vanguard’s current production by 10%. The company’s proved reserves at Dec 31, was pegged at approximately 203 billion cubic feetequivalent (Bcfe), increasing Vanguard’s estimated proved reserves by 10%.

The acquired company’s assets include roughly 1,290 gross producing wells and approximately 158,000 acres located in the Permian Basin in West Texas/Southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas, and the Texas Gulf Coast.

Vanguard also will acquire all of the limited liability company interests in LRR Energy GP for 12,320 Vanguard common units. The offer represents a 13% premium to LRR Energy’s closing price on April 20, and a 19% premium to LRR’s 10-day volume-weighted average price.

Vanguard and LRR Energy expect the transaction to close in the third quarter.

Citigroup Global Markets acted as exclusive financial advisor to Vanguard and Paul Hastings served as legal counsel to Vanguard. Tudor Pickering Holt served as exclusive financial advisor to LRR Energy, while Andrews Kurth and Richards Layton & Finger acted as legal counsel to LRR Energy.

4. Tesoro Logistics Acquiring Remaining Portion of QEP Midstream Partners - Posted: 4/7/2015 Oil and gas logistics provider Tesoro Logistics (TLLP) and QEP Midstream Partners on Monday, Aug 6, announced Tesoro will acquire QEP in a unit-for-unit exchange valued at roughly $456.3 million.

Under the terms of the deal, QEP unitholders will receive 0.3088 TLLP common units for each QEP common unit held, which values QEP units at $17.09 based on a Tesoro Logistics closing price Monday, April 6, of $55.34/unit.

C&J Energy Services and Nabors Industries said Tuesday, March 24, the completion of their $2.86 billion merger.

The offer represents an 8.5% premium to TLLP’s original proposal of 0.2846 TLLP units announced Dec 2, and an 8.6% premium to Monday’s QEP closing price of $15.74.

The combined company, renamed C&J Energy Services Ltd, is one of the largest completion and production services providers in North America, led by the current C&J management team, including Josh Comstock serving as CEO, and Randy McMullen serving as President.

“We are pleased to announce the execution of this agreement for the merger of QEP Midstream Partners into Tesoro Logistics,” said Greg Goff, CEO of TLLP’s general partner. “The merger will allow for a more simplified business structure, which is consistent with our integrated logistics strategy.”

The new C&J is headquartered in Bermuda and its common shares have been listed on the NYSE under the ticker symbol “CJES.”

TLLP currently owns a roughly 55.8% limited partner interest in QEP, consisting of 3.70 million common units, 26.71 million subordinated units, and 100% of the limited liability company interests of QEP GP, which holds a 2% general partner interest and 100% of the incentive distribution rights in QEP.

Nabors received approximately $688 million in cash from C&J as a portion of the consideration for the transaction and now owns approximately 53% of the outstanding and issued common shares of the new C&J, with the remainder held by former C&J shareholders.

“Today is an extraordinary and exciting day for both C&J and Nabors,” said Josh Comstock, Founder and CEO of the combined company. “Among the many strategic benefits of this combination is the transformative increase in scale, driving the rapid advancement of our goal of growing C&J from what we started as a singlecrew pressure pumping company to what is now a leading diversified provider of technologically advanced oilfield services.”

3. Vanguard Natural Resources Acquiring LRR Energy in $539 Million Unitand-Debt Deal - Posted: 4/21/2015 Houston-based independent producer Vanguard Natural Resources said Monday, April 20, it is acquiring fellow independent LRR Energy for $539 million in units and assumption of debt.

As a result of the deal, LRR Energy and its general partner will become whollyowned subsidiaries of Vanguard. The transaction will be a tax-free, unit-for-unit transaction with an exchange ratio of 0.55 Vanguard common units for each LRR Energy common unit.

The transaction is expected to close in 2015. Norton Rose Fulbright US acted as legal counsel to TLLP. Negative Job Losses (Top 4 Recent Job Loss Reports) 1. Crude Oil Price Crash Causes Schlumberger to Cut Another 11,000 Jobs Posted: 4/17/2015 Oilfield services firm Schlumberger announced Thursday, April 16, it plans to chop another 11,000 workers, initiating what some industry watchers say could be a second wave of layoffs across the industry.

The layoffs will bring Schlumberger’s layoffs up to 20,000 employees, roughly 15% of its workforce, since it began cutting payroll earlier this year to cope with low oil prices.

Schlumberger’s workforce peaked in the third quarter of 2014, at 126,000 employees.

Joao Felix, a Spokesman for Schlumberger, said the reductions should be completed in this quarter.

Schlumberger took a $390 million charge in the first quarter related to the job cuts and a company leave-of-absence program. It blamed the “severe fall” in North

May 2015

Page 21

American oil field activity as U.S. producers parked hundreds of drilling rigs and cut billions of dollars in spending.

Garcia added additional moves are likely in the second quarter but will probably result in much smaller charges.

The firm, the world’s biggest oil field services provider, said its first-quarter revenues fell to $10.2 billion, down 9% from the same January-March period last year.

4. Canadian Oil Industry Jobs, Revenue Expected to Plunge in 2015: Conference Board - Posted: 3/30/2015

Schlumberger’s North American revenue fell further than its international sales, declining 13% compared to the 8% revenue drop overseas.

The Canadian oil industry will drop nearly 8,000 jobs in 2015, as revenue plunges by $33.88 billion in response to the plunge in oil prices, projects the Conference Board of Canada.

2. Baker Hughes Cuts 3,500 Additional Jobs, 17% of Its Total Workforce - Posted: 4/21/2015 Oilfield services firm Baker Hughes, which is being acquired by its service company brethren Halliburton in a $34.6 billion deal, said Tuesday, April 21, it had cut 3,500 more staff during the first quarter than the 7,000 cuts announced in its fourthquarter report.

The 10,500 employees cut represent 17% of Houston-based Baker Hughes worldwide workforce.

The company said it also closed or consolidated roughly 140 facilities worldwide.

Baker Hughes said it expects those decisions to save more than $700 million annually.

Baker Hughes first-quarter results included a net loss of $589 million, compared to profit totaling $328 million one year earlier.

The loss reflected such adjustments as facility closures, severance payments, adjusted inventory, and merger costs, the company said.

Revenue also underwhelmed, falling nearly 20% year-over-year, to $4.59 billion.

3. Halliburton Admits Chopping 9,000 Jobs in Wake of Crude Oil’s Price Plunge - Posted: 4/21/2015 Oilfield services firm Halliburton revealed Monday, April 20, it has cut 9,000 jobs — more than 10% of its worldwide workforce — in roughly the last six months, and is considering more cost-cutting moves to deal with falling crude oil prices.

Halliburton executives disclosed the job cuts Monday, April 20, during a conference call with investors to discuss first-quarter results. The Houston-based company lost $643 million in the quarter.

Oil prices plunged beginning last June, leading to an ongoing decline in drilling. Spot prices for crude have risen slightly since early January, but remain about half their level of last July.

A new report released last week by the group predicts a pretax loss of more than $3 billion for the industry.

At current prices, the report says, new projects in the Canadian oil sands and tightoil plays are seen as uneconomic. The report adds break-even costs in the oil sands are $60-80/Bbl for a steam-assisted gravity drainage (SAGD) project, and $90-100/ Bbl for a mine.

The report projects oil investments will fall to $40 billion this year from $56 billion last year.

Still, total crude oil production in Canada will rise to 3.8 million barrels per day (MMBPD) this year from 3.6 MMBPD in 2014, as projects based on past investments come on stream.

The report projects an average oil price of $55/Bbl in 2015. Reduced investment will ease production growth as low oil prices spur demand.

“However, the days of triple-digit oil prices have passed for the immediate future,” the report says. “With the rise of horizontal drilling and hydraulic fracturing, the US industry will be able to quickly respond and increase production if prices reach $80/Bbl, putting a hard cap on prices.”

Conclusion The shale oil and gas industry affects everyone, whether they work in the industry or not. “People say they don’t have any skin in the game, if they aren’t employed in the oil and gas industry, but I would say everyone has skin in this game,” expressed Dave Spigelmyer, President, Marcellus Shale Coalition (MSC), referring to natural gas production and consumption at Upstream PA 2015.

Defining what having “skin in the game” means, Spigelmyer explained, “To turn your lights on 365 days a year, 24 hours a day, you need gas, coal, and nuclear power to provide baseload fuel supply. … Fossil fuels does not only involve power generation, but also includes: steel, glass, plastics, chemicals, fertilizers, powdered metals, and pharmaceuticals.” Clearly these positive and negative ripple effects in the shale oil and gas industry will affect everyone both now and in the future.

That has led to belt-tightening across the industry as producers move to curb production and chop capital expenditures, with oilfield services and drilling companies especially hard hit.

Haliburton competitor Schlumberger said last week it would chop 11,000 jobs on top of 9,000 planned job cuts announced in January.

“Once we see [drilling] activity stabilize, the healing process can begin, but it takes time,” Jeff Miller, President, Halliburton, told analysts.

The market decline caused Halliburton to take $1.2 billion in charges in the first quarter, including severance and write-offs, said Christian Garcia, Acting Chief Financial Officer, Halliburton. “Over the last two quarters we have reduced our head count by approximately 9,000 employees, more than 10% of our global head count,” he said on the conference call.

Shale Media Group (SMG) is the news, information, and education resource dedicated to the shale oil and gas industries by messaging across video, Internet, publications, events, and radio. For more, check out ShaleMediaGroup.com to access all platforms. In addition, join us on May 28th for our next Elite Energy Event in front of the Holiday Inn Express in Bentleyville, PA from 5-8pm. Rick Stouffer is the Senior Energy Editor at Shale Energy Business Briefing. Contact him at RStouffer@ShaleMediaGroup.com. Kristie Kubovic is the Director of Communications at Shale Media Group. Contact her at Kristie@ShaleMediaGroup. com.

Page 22

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19-21 Eastern Gas Compression Roundtable Pittsburgh, PA | www.egcr.org

19-20 NAPE South Houston, TX | www.napeexpo.com

20-21 SPE Produced Water Handling and Management Conference Galveston, TX | www.spe.org

25-26 IADC Well Control Conference Galveston, TX | www.iadc.org

20-21 North American Coalbed Methane Forum Canonsburg, PA | www.nacbmforum.com

SEPTEMBER 16-17

JUNE 22-25 A&WMA Annual Conference Raleigh, NC | www.ace2015.awma.org

23-25 DUG East Pittsburgh, PA | www.dugeast.com

Shale Insight Philadelphia, PA | www.shaleinsight.com

16-17 IADC Asset Integrity & Reliability Conference Houston, TX | www.iadc.org

16-19 ADDC Annual Convention Lubbock, TX | www.addc.org

17 SOOGA Annual Trade Show Marietta, OH | www.sooga.org

Denotes National Event

Visit our website for links to these events

WWW.ONGMARKETPLACE.COM/EVENTS

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May 2015

CALL FOR WHITE PAPERS! Share your expertise with over 11,000 monthly readers. Contact us to schedule an opportunity for the industry to learn what you know.

ONG Marketplace

info@ongmarketplace.com

855-269-1188

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The Northeast ONG Marketplace

NEW TECHNOLOGY

ELECTRIC, NATURAL-GAS DRIVEN UNITS POWER WELL STIMULATION By: Jared Oehring, Director of Technology, U.S. Well Services, LLC Fracturing operations are cleaner, quieter and less disruptive to neighboring communities at these Marcellus Shale sites.

Then in the annular type combustion chamber or combustor, fuel is added to the pressurized air molecules and ignited. The combustion chamber has 12 leanpremixed, dry low-emissions injectors, with a single torch ignitor system. As the heated molecules expand, they move at a high velocity into the turbine section.

The turbine converts the energy from the high-velocity gas into useful rotational power through the expansion of the heated compressed gas across three stages of turbine rotor blades that move in a clockwise direction. This rotation turns a generator that produces the electrical power used by the fleet.

The power generated by the turbines then runs through switchgear and is stepped down to 600 V using transformers. At this point, the electric powered fleet is similar to a conventional fleet, except that all the fleet’s diesel engines and transmissions— more than 20 of them—are replaced by electric motors and variable frequency drives (VFDs). The electric motors were designed specifically for oilfield operations and protect against overheating with 33 percent more copper and increased cooling to protect the motor and extend its life.

Figure 1: Dual electric powered hydraulic fracturing pump trailer. Images provided by U.S. Well Services, LLC and Solar Turbines

In March 2015, U.S. Well Services, LLC, a well servicing company, won the New Technology Development Award at the Oil & Gas Awards-Northeast for their Clean Fleet®. This technology is the first fully electric, fully mobile well stimulation system powered by natural gas. The electric hydraulic fracturing fleet was first implemented by Antero Resources at sites in the Marcellus Shale in West Virginia last year. At a recent investor’s call, Antero Resources CEO Paul Rady said, “We have been utilizing the first completions spread in the Marcellus since July, and it has truly delivered excellent performance for us.”

The fleet runs on electric power generated by three natural-gasfueled turbine engine generators.

Each one produces 5.7 megawatts electric (MWe) of three-phase output power at 13,800 volts (V) for a total of 17.1 MWe. Each mobile power unit consist of two trailers. The turbine engine and generator sit on the first trailer while the electric equipment room (EER) rides on the other.

The EER holds an auxiliary desktop computer, switchgear, carbon dioxide fire suppression system, and motor control center. The trailers for the mobile power units allow for much faster moves than traditional power generation stations. Each power plant has a compact footprint of 52 feet by 28 feet when fully installed.

Figure 2: Turbine Engine and Generator Trailer and Electronic Equipment Room Trailer.

Power Units The mobile power units use a single shaft, axial flow gas turbine engine. A turbine engine is composed of three primary parts: the compressor, the combustion chamber and the power turbine. In the compressor section the incoming air is compressed through a series of 12 rotating and stationary compressor blades.

Each electric motor is controlled by a VFD, which consists of three main parts: rectifier, direct current (DC) bus and inverter. Incoming three-phase, 600-V power enters the six-pulse rectifier bridge converter section, which converts the alternating current (AC) sine wave into unidirectional pulses of current that then enter the DC bus section. The DC bus section has a passive capacitive filter to minimize ripple and hold a constant steady DC. The voltage and current are continuously monitored to prevent damage to the drive and motor.

Next, the inverter section uses insulated gate bipolar transistors (IGBTs) for power switching to convert DC back to AC. The IGBTs switch the DC bus on and off at specific intervals, creating a variable frequency, three-phase, sinusoidal coded pulse width modulated (PWM) waveform. Alternating the positive and negative switches by the IGBTs allows the VFD to control the speed of the motor and hydraulic fracturing pump.

Environmental Benefits This electric-powered well stimulation fleet advances hydraulic environmental responsibility by reducing refueling traffic, site noise and emissions. While a conventional fleet must transport diesel fuel to the site, natural gas for the turbines is delivered more efficiently straight from a pipeline. Using Figure 3: Turbines with gas compression units natural gas eliminates the 25 diesel fuel truck deliveries to the well site that are required for an average horizontal well completion. This reduces traffic in communities while eliminating fire hazards and spills that may be associated with refueling. In addition, using the produced field gas reduces fuel operating costs by 80 percent.

Another environmental benefit of the electric powered fleet is reducing emissions to near-zero levels. The fleet is successfully decreasing emissions by 99 percent, mitigating environmental exposure to pollutants such as nitrogen oxides (NOx) (see Figure 1). Excess NOx can lead to acid rain and contribute to unhealthy ground-level ozone and smog. The reduction is primarily achieved by eliminating

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May 2015

Safety Finally, the electric fleet also increases safety by reducing high pressure iron vibrations by up to 80% when compared to diesel powered equipment. The results were proven by installing three dimension accelerometers on both diesel powered equipment and comparing this baseline to the accelerations seen by the electric powered equipment. The dramatic reduction in vibrations is achieved by replacing the engine and transmission with a VFD that controls the electric motor which is direct coupled to the hydraulic fracturing pump.

Figure 4: The electric fleet’s NOx emissions compared to EPA off-highway diesel engine standards

the conventional diesel engines and using natural gas as a fuel. The emissions on the turbines were measured in the exhaust ports by a third party, and the NOx levels were found to be near-zero at less than 0.036 grams per kilowatt hour (g/kWhr), resulting in a dramatic reduction when compared to Environmental Protection Agency (EPA) requirements for off-highway diesel engines.

Natural gas is a cleaner fuel than diesel because it produces fewer potential pollutants.

Natural gas turbine engines allow for a continuously burning combustion chamber that results in a more complete burn, which greatly reduces emissions when compared to a diesel engine’s four-stroke cycle. The gas turbines have a significant advantage because they use lean-premixed combustion technology to ensure a uniform air and fuel mixture and to prevent the formation of regulated pollutants.

Up to 60 percent of the airflow on the turbine engine is allowed to be premixed with the fuel resulting in a much more uniform air and fuel mixture (see Figure 2).

Noise Pollution Next, electric well stimulation significantly reduces noise pollution, making the workplace safer and disturbing communities less. Conventional well stimulation sites are extremely loud with some locations measuring as high as 129.5 decibels one foot away from the equipment. The well servicing company employed a third party to perform a sound survey of the electric fleet and compare it to a conventional site.

More than 140 total monitoring locations were used, and the result was up to a 69 percent reduction in the average sound pressure for the electric well stimulation site.

Figure 6: Significantly reduced vibrations for the electric fleet

An Improved Solution The electric well stimulation fleet has shown great advances in environmental responsibility and safety. U.S. Well Services, LLC believes that its development is a breakthrough for the industry and each of the communities that support hydraulic fracturing. Its adoption and results further validate the importance of conducting hydraulic fracturing in a more environmentally responsible manner. For more information please visit http://uswellservices.com or call 832-562-3730

NETWORKING EVENTS May 4 Women’s Energy Network Pittsburgh, PA | www.womensenergynetwork.org

May 6 YPE Crew Change Waynesburg, PA | www.ypepittsburgh.org

May 8 SOOGA Spring Golf Outing Beverly, OH | www.sooga.org

May 13 Oilfield Christian Fellowship Bridgeville, PA | www.oilfieldchristianfellowship.com

May 28 Elite Energy Event Bentleyville, PA | www.shalemediagroup.com

FOR MORE EVENTS VISIT WWW.ONGMARKETPLACE.COM/EVENTS

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The Northeast ONG Marketplace

LEGAL & FINANCE

PROMOTING NATURAL GAS IN YOUR COMMUNITY By: Robert Johnson, President, ADKL Is your community reviewing its oil and gas ordinance? Do you have an oil and gas ordinance in your township?

As the natural gas industry continues expansion in PA, Ohio, and West Virginia we must support natural gas exploration at the local level. More drilling and pipeline construction is being planned.

Midstream and downstream development will be adversely affected if zoning prevents drilling or pipeline construction.

In Western Pennsylvania, pending regulations in South Fayette Township (Allegheny County) and Ligonier Township (Westmoreland County) will make natural gas exploration very difficult.

Conversely, pro-energy supporters are pushing back against the anti-fracking crowd in communities like Middlesex Township (Butler County) and Penn Township (Westmoreland County). In Pennsylvania, due to the recent State Supreme Court Act 13 decision, municipalities are reviewing their oil and gas regulations. Areas being reviewed are setback requirements for well pads, drilling in certain zoning districts, and environmental impacts.

State laws have set guidelines for drilling and pipeline development. With the encouragement of anti-frackers, some municipalities are moving towards far more restrictive regulations. For example, South Fayette Township only permits drilling in a small number of industrial zones. Ligonier Township is currently considering a gas ordinance similar to South Fayette’s. The proposed ordinance would restrict natural gas development in most of the community.

A major regulation being discussed is setback requirements. Act 13 of PA established a setback of five hundred feet from dwellings. Anti-frackers are urging municipalities to move this requirement back to two thousand feet or more in an effort to stop natural gas exploration. They also push for restricting drilling to certain municipal zones such as industrial use. Private property rights are affected by this type of regulation. Property owners who own mineral rights have a right to sign leases. Environmental activists are stating publicly their intention of protesting all pipeline development in every municipality.

We must pay attention to what is happening at the local level. Identify and talk with your elected officials, township staff, and solicitor if you have not already done so. Find out their monthly meeting schedules and attend whenever possible. Send them facts about drilling and pipelines. These facts should address environmental safety regulations as well as the economic benefits of natural gas. Existing state and federal regulation of the gas industry must be highlighted. These rules were established to ensure the safe exploration of natural gas. Municipal officials do not need to reinvent regulation that has been established at the State/ Federal level by industry and environmental experts.

Talk to leaseholders in your community and let them know what is going on. Also, energy workers and small business service providers should be asked to support the industry since they are most affected by attempts to stop natural gas exploration.

Agriculture has benefitted greatly from natural gas exploration. Family farms are being saved from development due to revenue from natural gas. Make sure your farmers are included in local advocacy efforts.

With your efforts, we will succeed in further developing domestic energy and share in its many economic benefits.

Robert Johnson can be reached at rjohnson@adkl.org. His website is www.adkl. org.

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May 2015

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Page 28

The Northeast ONG Marketplace

David L. Lawrence Convention Center

June 23-25, 2015

Pittsburgh, PA

PLAYS

COVERED:

Marcellus Utica

Resource Resilience Engineers enhance value in a prolific gas/liquids province Producers in the Marcellus and Utica know exactly what it takes to succeed in a low-price commodity market. By constantly evolving the technology and methods behind their operations, they have successfully cut breakeven costs from around $4/Mcf in 2008 to less than $2/Mcf today. In 2014, Marcellus production grew 21% despite a 32% fall in prices. Pad drilling and extending horizontal well lengths are just a few of the efficiency improvements producers are making to help them increase output in the face of a challenging price environment.

Innovation and collaboration are key to remaining successful in the prolific Marcellus-Utica region. This June, join 3,100+ industry professionals, 20+ executive-level speakers and 320+ exhibitors at DUG East 2015 for an in-depth look at all the technologies and emerging trends that will continue to drive the industry forward.

FEATURED SPEAKERS

LUNCHEON KEYNOTE: Dr. Charles Krauthammer Columnist, Author and Pulitzer Prize Winner

Presented by:

Adam Sieminski Administrator Energy Information Administration

Hosted by:

Thomas A. Petrie Founder and Chairman Petrie Partners LLC

Jeffrey Ventura Chairman, President and CEO Range Resources

Benjamin W. Hulburt CEO, President and Chairman of the Board of Directors Eclipse Resources Corporation