OTC Exhibitors: Technologies Trending Toward Deeper Water But Also Land

Based on a quick sampling of insights from a few of the more than 2,700 exhibitors at the Offshore Technology Conference (OTC) 2013 in Houston this past week, applications of innovations developed to expand the frontiers of the offshore oil and gas industry are broadening. However, they pointed out that larger companies stand to benefit from this trend.

"I think there is more emphasis on the higher pressures and higher temperatures that the wells, that the equipment, have to accommodate," said Paul Taylor, sales director with Trelleborg Sealing Solutions UK.

Trelleborg, which produces sealing systems for offshore applications such as seismic guns and well head connectors, is modifying how it manufactures and configures these parts so that they can endure these increasingly extreme conditions, Taylor said.

"We're looking at polymers technology to make sure that our product can accommodate the higher temperatures and the higher pressures," Taylor said.

Although the offshore industry is demanding seals and myriad other products that can withstand higher temperatures and pressures, Taylor added that it is seeking more evidence to substantiate the claims made by manufacturers.

"There's becoming an increasing emphasis on the certification of the parts," he explained.

"I think everybody has learned from the Deepwater Horizon that the industry is becoming perhaps a little bit more conservative on insisting the parts that they purchase are endorsed and validated with certificates of conformity."

The increased level of scrutiny – driven in part by more attention from government authorities – applies to constituent parts, measurements and testing, said Taylor. In addition, he believes this trend will benefit larger suppliers such as Trelleborg.

"I think what it will do is probably reinforce what has been done by the larger, more innovative companies that are going with the trends," Taylor noted.

He explained that smaller companies unable to validate the sources of their raw materials, conduct research and development, perform testing and take sundry other steps will be at a disadvantage.

"I think they'll get less and less business and the bigger companies, the bigger original equipment manufacturer end users, will use the bigger, more efficient companies," predicted Taylor. "So there may be a rationalization of competition in our industry as a consequence."

Jeffrey Lavers, vice president and general manager of 3M Mining's Oil and Gas Solutions Division, noted that the oil and gas industry's quest to exploit reserves in deeper waters off West Africa and other regions demands continual innovation from companies such as his.

"Just the basic pressure and force of going that deep in the water, from an engineering standpoint, changes a lot of dynamics of the project," said Lavers. "It's a much more challenging environment in a host of different ways, primarily just because of the heat and the pressure."

"What we have to do is adjust some of our products and we think, candidly, it puts us in a good position because we have the capabilities" to make those adjustments, he added.

Lavers said that 3M is also responding to oil and gas industry needs in mature offshore provinces such as the Gulf of Mexico and North Sea. Although many depleted wells in these areas still contain significant volumes of hydrocarbons and boast well-developed infrastructure, inadequate flow rates from these wells prevent the economic exploitation of the remain resources. 3M is also working to tailor some of its products to perform in these types of situations.

"We're gearing up a lot of technology to see if we can go back to these brownfield wells and make them productive," Lavers said.

Another company aiming to re-purpose existing technology is Tesco Corp., which provides drilling and tubular services technologies for land, offshore and deepwater operations.

Jeff Foster, senior vice president of Tesco's Top Drive business segment, said that more offshore technology is being transferred to land applications in the area of automation and rig mechanization. He explained that "iron roughnecks," which connect and disconnect drill pipe, and top-drive drilling systems are two examples of offshore technologies that are being adapted for onshore use.

Foster said the automation, preventive and predictive maintenance trend offers Tesco and other service providers an opportunity to reduce non-productive time.

"It's an add-on for us," he said.

Late Thursday, OTC organizer Society for Petroleum Engineers (SPE) reported that attendance at the 2013 event hit 104,800 – a 17-percent increase from last year's conference and the second-highest since the show began in 1969.

"We had a terrific conference with deep and broad technical coverage, supported by excellent panels and executive keynote presentations," OTC chairman Steve Balint said in a written statement. "Technology is at the heart of the offshore industry and it was all here on display at OTC 2013."

Houston's Reliant Park will again be the venue for the next OTC, which will run from May 5-8, 2014.

Matthew V. Veazey has written about the upstream and downstream O&G sectors for more than a decade. Email Matthew at mveazey@downstreamtoday.com. Twitter: @Matthew_Veazey

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

OTC Exhibitors: Technologies Trending Toward Deeper Water But Also Land

Based on a quick sampling of insights from a few of the more than 2,700 exhibitors at the Offshore Technology Conference (OTC) 2013 in Houston this past week, applications of innovations developed to expand the frontiers of the offshore oil and gas industry are broadening. However, they pointed out that larger companies stand to benefit from this trend.

"I think there is more emphasis on the higher pressures and higher temperatures that the wells, that the equipment, have to accommodate," said Paul Taylor, sales director with Trelleborg Sealing Solutions UK.

Trelleborg, which produces sealing systems for offshore applications such as seismic guns and well head connectors, is modifying how it manufactures and configures these parts so that they can endure these increasingly extreme conditions, Taylor said.

"We're looking at polymers technology to make sure that our product can accommodate the higher temperatures and the higher pressures," Taylor said.

Although the offshore industry is demanding seals and myriad other products that can withstand higher temperatures and pressures, Taylor added that it is seeking more evidence to substantiate the claims made by manufacturers.

"There's becoming an increasing emphasis on the certification of the parts," he explained.

"I think everybody has learned from the Deepwater Horizon that the industry is becoming perhaps a little bit more conservative on insisting the parts that they purchase are endorsed and validated with certificates of conformity."

The increased level of scrutiny – driven in part by more attention from government authorities – applies to constituent parts, measurements and testing, said Taylor. In addition, he believes this trend will benefit larger suppliers such as Trelleborg.

"I think what it will do is probably reinforce what has been done by the larger, more innovative companies that are going with the trends," Taylor noted.

He explained that smaller companies unable to validate the sources of their raw materials, conduct research and development, perform testing and take sundry other steps will be at a disadvantage.

"I think they'll get less and less business and the bigger companies, the bigger original equipment manufacturer end users, will use the bigger, more efficient companies," predicted Taylor. "So there may be a rationalization of competition in our industry as a consequence."

Jeffrey Lavers, vice president and general manager of 3M Mining's Oil and Gas Solutions Division, noted that the oil and gas industry's quest to exploit reserves in deeper waters off West Africa and other regions demands continual innovation from companies such as his.

"Just the basic pressure and force of going that deep in the water, from an engineering standpoint, changes a lot of dynamics of the project," said Lavers. "It's a much more challenging environment in a host of different ways, primarily just because of the heat and the pressure."

"What we have to do is adjust some of our products and we think, candidly, it puts us in a good position because we have the capabilities" to make those adjustments, he added.

Lavers said that 3M is also responding to oil and gas industry needs in mature offshore provinces such as the Gulf of Mexico and North Sea. Although many depleted wells in these areas still contain significant volumes of hydrocarbons and boast well-developed infrastructure, inadequate flow rates from these wells prevent the economic exploitation of the remain resources. 3M is also working to tailor some of its products to perform in these types of situations.

"We're gearing up a lot of technology to see if we can go back to these brownfield wells and make them productive," Lavers said.

Another company aiming to re-purpose existing technology is Tesco Corp., which provides drilling and tubular services technologies for land, offshore and deepwater operations.

Jeff Foster, senior vice president of Tesco's Top Drive business segment, said that more offshore technology is being transferred to land applications in the area of automation and rig mechanization. He explained that "iron roughnecks," which connect and disconnect drill pipe, and top-drive drilling systems are two examples of offshore technologies that are being adapted for onshore use.

Foster said the automation, preventive and predictive maintenance trend offers Tesco and other service providers an opportunity to reduce non-productive time.

"It's an add-on for us," he said.

Late Thursday, OTC organizer Society for Petroleum Engineers (SPE) reported that attendance at the 2013 event hit 104,800 – a 17-percent increase from last year's conference and the second-highest since the show began in 1969.

"We had a terrific conference with deep and broad technical coverage, supported by excellent panels and executive keynote presentations," OTC chairman Steve Balint said in a written statement. "Technology is at the heart of the offshore industry and it was all here on display at OTC 2013."

Houston's Reliant Park will again be the venue for the next OTC, which will run from May 5-8, 2014.

Matthew V. Veazey has written about the upstream and downstream O&G sectors for more than a decade. Email Matthew at mveazey@downstreamtoday.com. Twitter: @Matthew_Veazey

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

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New System Offers Holistic Approach to Frack Water Treatment

A wastewater treatment process long utilized in the food industry now is available to treat flowback and produced water from hydraulic fracturing.

Established in 2002, Alpharetta, Georgia-based Ecologix Environmental Systems has provided wastewater treatment services to companies such as Tyson, Kellogg's and Toyota as well as mining and metal plating industries.

The company has reached agreements to ship its wastewater treatment management system to oil and gas customers in Canada and Texas. These units are the third generation of systems geared towards the oil and gas industry – the company previously had sent protoypes into the field in Oklahoma and Texas' Permian basin to learn the lessons of what and what not to do. These lessons include everything from how to maximize unit performance, improve manufacturing and make the units more user-friendly in terms of maintenance and ground operations.

The company also sold a prototype unit to Halliburton Co. that reduced the turbidity level from 530 nephelometric turbidity unit (NTU) to just 3 NTU, a 176 fold improvement in water clarity.

When Ecologix CEO Eli Gruber looked at the oil and gas industry, he saw nothing had been done to address wastewater treatment in a way that made sense to him. Various companies had rushed in with black box ideas, but Gruber still saw a need for a water solution to correct the whole spectrum of contaminants.

"Other companies who rushed in do one thing well, but they ignore five other things," Gruber told Rigzone in a recent interview. "We attempt to take care of every step along the way to  both clean and disinfected the water."

Ecologix Environmental Systems' flagship ITS-900 units for frac water recycling. Each system can process up to 31,000 barrels per day of flowback or produced water.

Ecologix's Integrated Treatment System (ITS) for hydraulic fracturing water treatment allows water to be treated near the well pad, allowing the storage and transportation costs of produced and flowback water to be eliminated.  The ITS also eliminates the need for fresh water withdrawal, shortens hauling distances and reduces truck traffic and creates reusable water from waste, eliminating need for water disposal.

The platform uses a basic wastewater treatment process, Dissolved Air Floatation (DAF), which uses targeted chemicals to precipitate oils and solids out of suspension and a physical mechanism to remove these solids from the water.  In the DAF process, millions of tiny air bubbles force total dissolved solids and fats oil and grease to flow to the surface, where they can be skimmed away. Through this process, over 99 percent of the sludge can be removed.

The ITS-900 consists of three main units:

to control chemical dosingto mix the chemicals into the waterto perform the physical separation of solids

The ITS process is flexible, and can be adapted to meet the specific needs of the formation and driller preferences.

The ITS platform is available in two sizes: one that can process 900 gallons per minute, or 31,000 barrels per day, and a fourth generation ITS that can process 500 gallons per minute, or 17,000 barrels per day. The fourth generation ITS has a lower processing rate, but it has a smaller footprint that combines equipment from two trailers into one. The company will limit production of the units to the smaller unit, noting that customers can always choose to utilize two ITS-500 units, if the volume of water justifies it, Gruber noted.

"However, the 17,000 barrels per day unit seems to be within the industry's sweet spot for most fracking operations," Gruber noted.

EcoLogix's Integrated Treatment System offers a holistic approach to wastewater treatment for the oil and gas industry.

The oil and gas industry's increased use of hydraulic fracturing to explore for and produce unconventional oil and gas has made the treatment of produced and flowback water a top concern for the oil and gas industry, environmentalists and the government. 

Between one and five million gallons of water are used in the hydraulic fracturing of one well. The high volume of water used in this process has raised concerns about water resources used in agriculture or drinking water being diverted towards hydraulic fracturing instead, particularly in areas that have or are experiencing drought conditions. The impact on drinking water supplies due in part to the disposal of flowback and produced water, which could contain organic chemicals, metals, salts and naturally occurring radionuclides, is another issue.

To deal with wastewater, oil and gas operators have either injected wastewater into disposal wells or hauled water away by truck. However, some studies have indicated that injecting hydraulic fracturing wastewater injection into disposal wells can trigger earthquakes. A recent study tied a series of earthquakes in central Oklahoma to the injection of wastewater deep underground. Additionally, high salt levels in water can reduce the number and types of organisms found at a site, impacting the entire ecosystem, according to a recent study Australian and European researchers. 

The heavy traffic of trucks hauling wastewater and other materials related to shale exploration and production has resulted in wear and tear on roads around the country. Almost 1,200 loaded trucks are needed to bring one gas well into production, over 350 are required each year for maintaining a gas well, and nearly 1,000 are needed every five years to refracture a well, according to the March 2013 Eagle Ford Shale Task Report. In many places, the existing roads are not equipped to handle the weight and volume of this traffic.

Gruber sees his company's technology as a way to keep both environmentalists and the oil and gas industry happy.

"What appears to be clean may not be clean," Gruber commented, noting that the oil and gas industry's previous attempts to clean water fell short.

By using a short-cut approach, only 20 percent of suspended solids are removed from water, and without a chemical solution, only larger suspended solids will be removed, leaving small suspended particles behind. These smaller  suspended solids, called colloidal, have very large surface area that add friction to the gelling agents and friction reducers, negatively affecting the viscosity of the fluid from carrying the  proppant sand further distances in the water and keep the hydraulic fractures open, impacting the efficacy of a frack job.

Arguments have been made by some in the oil and gas industry that salt must be completely removed from the water to make it suitable for reuse in hydraulic fracturing, Gruber stated that this is simply not the case.

Gruber cited a recent study conducted by Halliburton and XTO Energy and that the level of salt in water does not impact the quality of a hydraulic fracturing job as long as the total suspended solids have been removed. This finding means that oil and gas companies do not have to remove water from aquifers, meaning this water can be saved for agriculture or other purposes.

In the study, Halliburton and XTO found that produced water with total dissolved solids levels as higher 285,000 milligrams per liter, or 28.5 percent salinity, was shown to generate proper cross-linked rheology for hydraulic fracturing in line with wells that were fracturing with just 20,000 particles per million, or 2 percent salinity.

The study results, which were published by the Society of Petroleum Engineers earlier this year, came from a test of seven wells in New Mexico's Delaware Basin. In the field study, a mixture of common drilling chemicals, such as Cacrboxymethyl Hydroxypropyl Guar Gum, a zirconium-based cross linker, sodium chlorite breakers and non-emulsified surfactants were blended with 100 percent treated produced water to generate a frac fluid that performed as well as that expected from a fluid based on fresh water.  

"The study shows that brine water possesses all the characteristics required for effective fracking: easy preparation, rapid hydration, low fluid loss, good proppant transport capacity, low pipe friction, and effective recovery from the reservoir," said Gruber in a recent white paper in regards to the Halliburton-XTO study. "Unlike fresh water, salt water does not restrict oil flow because of an osmotic imbalance that results in clay swelling."

That study also indicated that by using produced water for hydraulic fracturing can help reduce approximately 1,400 truckloads from the roads, and all but eliminate the use of disposal wells. The study delivered $70,000 to $100,000 cost savings per well.

"Removing the suspended solids is the key," Gruber commented. "If you take shortcuts, you compromise the quality of the hydraulic fracturing job."

For this reason, 100 percent brine water can be used for hydraulic fracturing, so long as the suspended solids are removed completely.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

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Study: Oil, Gas Industry Needs to Step Up Water Management

The oil and gas industry needs to step up efforts to expand its use of recycled water and non-freshwater resources and implement better water management planning if shale energy production is to expand according to projections.

Research conducted by San Francisco-based CERES indicates that nearly 47 percent of wells were developed in water basins with high or extremely high water stress. Most of the hydraulic fracturing activity in the United States is occurring in Texas and Colorado, which are experiencing prolonged drought conditions.

The report is based on well drilling and water use data from FracFocus.org and water stress indicator maps developed by the World Resources Institute. The research was based on FracFocus’ data on 25,450 wells in operation from January 2011 through September 2012.

Ninety-two percent of Colorado wells analyzed in the report are in extremely high water stress regions. In Texas, which accounts for nearly half of the total wells analyzed, 51 percent of the wells were in high or extremely high water stress regions. Water use in hydraulic fracturing in some Texas counties accounted for over 20 percent of the region's total water use. Concerns over water usage for hydraulic fracturing in Texas prompted legislators to mandate water recycling in the oil and gas industry.

Seventy percent of the wells analyzed in Pennsylvania were in medium to high water stress water basins and only 2 percent were in high water stress basins.

"Given projected sharp increases in shale oil and gas production in the coming years, competition over water should be a growing concern to energy companies," CERES concluded in the report, noting that hydraulically fractured oil and gas production is expected to double in the coming years. "Shale energy development cannot grow without water, but in order to do so the industry's water needs and impacts need to be better understood, measured and managed."

The industry has made progress in increasing its use of recycled water and other alternative water sources for fracturing wells, including non-freshwater alternatives such as wastewater, saline water, seawater and acid-mine drainage. But overall water recycling and use of non-freshwater sources must rise considerably to have a significant impact.

Key recommendations by CERES for companies and regulators include:

Comprehensive mandatory disclosure by companies of how much freshwater, non-freshwater and recycled water they are using region by region as well as how much water is returning to the surface and where it is ending upRequirements for companies to set quantifiable water use targets, such as recycling and non-freshwater use targetsEnsure that companies and local regulators are conducting sufficient water management planningEnsure companies have a local stakeholder engagement process in place on water issues

The U.S. oil and gas industry's increased exploration and production of U.S. unconventional resources has increased the amount of water being used by the oil and gas industry in its operations.

Best practices for water management in unconventional exploration and production activity are still evolving as companies address water use management issues such as the cost of transporting water to drilling sites, whether to treat or dispose of water, and concerns by environmental groups, state officials and the U.S. public over the amount of water used and the impact of hydraulic fracturing on water supply in shale regions.

A number of water treatment processes are also becoming available to the oil and gas industry, including EcoLogix and EcoSphere, which Rigzone reported on last year.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

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Legislation Targets Mandates for Water Recycling in Oil, Gas Industry

Legislation introduced last week into the Texas Legislature mandating the recycling of produced and flowback water from hydraulic fracturing operations mark the most recent efforts by lawmakers to make water recycling mandatory.

With Texas' population expected to reach 46.3 million people over the next 50 years, drought conditions over the past three years and water shortages over the past five years, oil and gas and other industries that consume a significant amount of water have been scrutinized by the public, environmental groups and government officials. Texas does not have enough existing supplies today to meet demand for water in times of drought, according to Texas' State Water Plan.

Concerns about water usage have grown in recent years not only in Texas, but communities across the United States, said Gabriel E. Eckstein, an attorney with the law firm Sullivan & Worcester and a professor specializing in water, environmental, natural resources and international law at Texas Weslayan University School of Law in Fort Worth, in an interview with Rigzone. In recent years, a host of water-related bills from the construction of new dams to aquifer storage to water recycling have been introduced to the state legislature, Eckstein commented. Major discussions have also taken place to use money from the state's Rainy Day Fund as seed money for infrastructure to meet Texas' future water supply needs.

The surge in exploration and production and unconventional resources in the Eagle Ford and other shale plays in Texas has created concerns in recent years over the amount of water being used in hydraulic fracturing and hydraulic fracturing's impact on local water supplies. The hydraulic fracturing process involves injecting a mixture of water, sand and chemicals into a well at high pressure to create fissures to release oil and gas deposits. Water usage varies on the size and conditions of the shale formation, with Haynesville shale requiring close to 8 million gallons per well, followed by the Eagle Ford play at 5 million and Barnett shale at over 4 million gallons.

From 2008 to 2011, total water used in hydraulic fracturing in Texas grew from 36,000 in 2008 to 81,500 acre-feet in 2011, according to "Oil and Gas Water Use in Texas: Update to the 2011 Mining Water Use Report". In 2011, the oil and gas industry used 102,500 acre-feet of water, including approximately 81,500 acre-feet for hydraulically fracturing wells and approximately 21,000 acre feet for other oil and gas industry purposes.

Water used in oil and gas exploration, development and extraction and for mining represented 1.6 percent of Texas' total water use, while irrigation and municipal water use collectively represented 82.8 percent of water use in the state, according to the Texas Water Development Board's 2012 State Water Plan. However, in the Eagle Ford shale region, mining accounts for 6.5 percent of water demand; that demand is expected to increase by 26 percent from 2010 to 2060 for the region, according to Luke Metzger, head of Environment Texas.

While water demand for municipal use, manufacturing, and steam electric power generation are expected to rise over the next 50 years, water demand for oil and gas and mining is expected to remain relatively constant and then decline over that period. By 2060, mining water use is expected to decline slightly from 1.6 percent to 1.3 percent for Texas' total water use, according to "March 2013 Eagle Ford Shale Task Force Report".

Last month, the Texas Railroad Commission (TRC) adopted rules to encourage Texas oil and gas operators to continue conserving water used in hydraulic fracturing. These new amendments do not make recycling mandatory for operators.

"However, they are expected to encourage recycling by eliminating the need for a permit for on lease fluid recycling, streamlining the recycling permitting process and providing operators with clear path to securing the Commission permits," a TRC spokesperson told Rigzone in an email.

The TRC's new and updated recycling rules authorize an operator or its contractor to store and recycle well fluids on an oil and gas lease, allow the operators to recycle each other's fluids, and establish protective standards for fluid storage and recycling, the spokesperson said.

For recycling activity that requires a permit, the rules clearly identify application requirements and establish categories of commercial recycling permits to reflect industry practices in the field, the spokesperson said. The amended rules are scheduled to take effect April 15.

Despite the new TRC regulations, some state lawmakers have sought to take matters a step further and require oil and gas operators to recycle water. House Bill 2992, introduced by Rep. Tracy O. King (D-Batesville) would prohibit hydraulic fracturing flowback fluid and water produced from a hydraulically fractured well from being injected into a disposal well unless the fluid cannot be treated so it could be recycled in hydraulic fracturing, used for another beneficial purpose or be released into or near the state's water system.

The bill would also require the TRC to adopt rules establishing standards for determining whether flowback and produced water may be disposed of in an oil and gas waste disposal well.

The TRC has said it would need to track flowback fluid from the point of generation to the point of ultimate disposition for beneficial use or disposal, with certification that the fluid cannot be treated for beneficial use to allow disposal into an injection well. This would require additional inspections; the TRC estimates it would need an additional 16,200 inspections to track this data.

These inspections would be conducted on a different schedule from the current inspection workload, and would focus on tracing the origins and use and treatment of flowback fluid. To implement this bill, 21 full-time employees would be needed, including three at the TRC headquarters to manage the tracking system and to enforce the new requirements, as well as two full-time inspectors at each of the agency's nine district offices to enforce the bill's requirements. These costs are estimated at approximately $1.4 million per fiscal year.

The TRC would also need to establish a complex water tracking system to determine water treatment and ultimate disposal. To track flowback and produced fluid and their method of disposal, the TRC would have to develop an application that would allow for operators to file the volumes of flowback and produced water from an oil and gas well on a monthly basis, along with how these volumes are disposed. The estimated cost to develop the necessary technology in 2014 is $486,720.

HB 3537, introduced by Rep. Roland Gutierrez (D-San Antonio) would require the TRC to adopt rules requiring treatment of flowback and produced water from oil and gas wells that have been hydraulically fractured. The bill would only apply to fluid produced from an oil and gas well on or after the bill's effective date.

Both bills would require TRC to adopt the new rules no later than Dec. 1 of this year, and would take effect Sept. 1, 2013. The legislation does not expect HB3537 to have any significant fiscal impact to the agency.

The new bills aren't the first time lawmakers have sought to make recycling of water from hydraulic fracturing operations mandatory. During the 2011-2012 session, Rep. Lon Burnam (D-Forth Worth) proposed HB 378, which would have required oil and gas operators to pay $.01/barrel tax for every barrel of hydraulic fracturing wastewater injected into a disposal well. That measurement did not pass.

Environment Texas voiced support for HB 2992 and HB 3537, noting that the statewide percentage of water demand in oil and gas drilling and mining belies the impact of oil and gas extraction on water supplies in the few areas of the state where oil and gas production is most prevalent, said Metzger in a statement to Rigzone.

However, oil and gas industry executives say incentives, not mandates, are the best way for Texas to encourage oil and gas operators to recycle water from hydraulic fracturing operations.

"The TRC deserves credit for creating rules that are fair and that help remove impediments to increased recycling in Texas," said Brent Halldorson, chief operating officer of water recycling firm Aqua-Pure/Fountain, told Rigzone in an email.

Recycling is being actively included in exploration and production companies' water management strategies, Halldorson added.

The rules already adopted by the TRC which would allow recycling without acquiring a new permit to do so actually go a long way to encourage recycling compared to a mandate, and for exploration and production companies to adopt recycling, mainly because they can store the water onsite so that they can recycle it, said Anthony Migyanka, CEO of Irving, Texas-based water treatment firm CLLEEN, in a statement to Rigzone.

Texas exploration and production companies have built-in incentives to recycle: water scarcity, drought and transportation costs, Migyanka commented.

"I think if they give them time to play out, the drillers and their water treatment vendors will find better recycle economics versus just taxing them into doing it. And long-term, they would benefit everyone using water."

"It would take a $3/bbl brine well injection tax, not a $.01/bbl tax, at least theoretically, to change the workflow from disposal to recycle, but I don't know that it would improve the economics of recycling water, which is really what Texas wants, and it's what the drillers want too," Migyanka commented. "It would just cause price inflation. What if the drillers simply decide to pay the tax? That's not saving any water, which is the point of the proposed legislation."

The amount of water recycled from hydraulic fracturing is difficult to pinpoint, Migyanka noted. Metzger noted that the low level of flowback water recycled in Texas is partly due to the high cost associated with treating this water. An estimated 5 percent of Barnett shale flowback is recycled and reused.

"It all comes down to down to the total economic picture of the water: how much is it to buy fresh? How far is that in miles? How close is the nearest injection well? How far is the next well where we want to use the water?" Migyanka noted. "So, more than just brine injection well prices comes into play. It's quite a complex issue, really."

Migyanka sees increased adoption of water reuse from one fracking stage to the next, over and over, and not having to reformulate the frac fluid formulation. A biocide is used to kill the bugs in the water that cause corrosion, and water is reused four or five times instead of once before being disposed. This trend is catching on in Texas, Oklahoma, Colorado and other places of true water scarcity and drought.

He also sees high total dissolved solids fracking as the biggest factor in water recycling in the coming years.

"Initially, it was thought that the water needed to be at 25,000 to 40,000 parts per million (ppm) TDS, such as iron aluminum, calcium and sodium) but what testing and experience has shown is that they can frack a well with TDS levels as high as 285,000 ppm TDS, so that the water is pumped in the well at 25,000 ppm, flows back at 100,000 ppm, they reuse it with biocide-only treatment, they refrack at 100,000 ppm, it flows back at 150,000 ppm," said Migyanka. "They reuse it again, and so on, until they are done with that well."

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

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TRC Adopts New Hydraulic Fracturing Water Reuse Rules

The Texas Railroad Commission (TRC) Tuesday adopted new rules to encourage Texas operators to continue their efforts at conserving water used in the hydraulic fracturing process for oil and gas wells, even though hydraulic fracturing and total mining use accounts for less than 1 percent of statewide water use, with irrigation, municipalities and manufacturing making up state’s top three water consumers.

Major changes adopted to the Commission’s water recycling rules include eliminating the need for a Commission recycling permit if operators are recycling fluid on their own leases or transferring their fluids to another operator’s lease for recycling. The changes adopted by the Commission today also clearly identify recycling permit application requirements and reflect existing standard field conditions for recycling permits.

Chairman Barry Smitherman said, "By removing regulatory hurdles, these new amendments will help foster the recycling efforts by oil and gas operators who continue to examine ways to reduce freshwater use when hydraulically fracturing well."

Commissioner David Porter said, "Water use has been a major concern examined by my Eagle Ford Shale Task Force, and I commend our staff for working to streamline our rules to encourage more recycling."

Commissioner Christi Craddick said, "Just as our operators have used technology to bring us into this modern day boom of oil production, they are also using technology to reduce their fresh water use. The changes adopted today will assist in those efforts."

The rule amendment also establishes five categories of commercial recycling permits to reflect industry practices in the field:

On-lease Commercial Solid Oil and Gas Waste Recycling

Off-lease or Centralized Commercial Solid Oil and Gas Waste Recycling

Stationary Commercial Solid Oil and Gas Waste Recycling

Off-lease Commercial Recycling of Fluid; and

Stationary Commercial Recycling of Fluid

The changes to the rule also establish a tiered approach for the reuse of treated fluid, including both authorized reuse of treated fluids in oil and gas operations and provisions for reusing the fluid for other non-oilfield related uses.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

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TRC Adopts New Hydraulic Fracturing Water Reuse Rules

The Texas Railroad Commission (TRC) Tuesday adopted new rules to encourage Texas operators to continue their efforts at conserving water used in the hydraulic fracturing process for oil and gas wells, even though hydraulic fracturing and total mining use accounts for less than 1 percent of statewide water use, with irrigation, municipalities and manufacturing making up state’s top three water consumers.

Major changes adopted to the Commission’s water recycling rules include eliminating the need for a Commission recycling permit if operators are recycling fluid on their own leases or transferring their fluids to another operator’s lease for recycling. The changes adopted by the Commission today also clearly identify recycling permit application requirements and reflect existing standard field conditions for recycling permits.

Chairman Barry Smitherman said, "By removing regulatory hurdles, these new amendments will help foster the recycling efforts by oil and gas operators who continue to examine ways to reduce freshwater use when hydraulically fracturing well."

Commissioner David Porter said, "Water use has been a major concern examined by my Eagle Ford Shale Task Force, and I commend our staff for working to streamline our rules to encourage more recycling."

Commissioner Christi Craddick said, "Just as our operators have used technology to bring us into this modern day boom of oil production, they are also using technology to reduce their fresh water use. The changes adopted today will assist in those efforts."

The rule amendment also establishes five categories of commercial recycling permits to reflect industry practices in the field:

On-lease Commercial Solid Oil and Gas Waste Recycling

Off-lease or Centralized Commercial Solid Oil and Gas Waste Recycling

Stationary Commercial Solid Oil and Gas Waste Recycling

Off-lease Commercial Recycling of Fluid; and

Stationary Commercial Recycling of Fluid

The changes to the rule also establish a tiered approach for the reuse of treated fluid, including both authorized reuse of treated fluids in oil and gas operations and provisions for reusing the fluid for other non-oilfield related uses.

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H2O Offshore Becomes Leading Unique Water Treatment Co with Acquisition

H2O Offshore, Inc., a leading water treatment equipment provider, has acquired Lafayette-based Owens Manufacturing & Specialty Company, Inc., announced H2O President Jess Fike.

With the addition of Owens' wastewater treatment products to H2O's Crapzapper division, H2O is now a one-stop source for all the unique water treatment needs of the oil and gas industry.

With a well-known presence in the global marine and offshore market, Owens' products will still be available to domestic and international drilling companies and oil and gas operators.

"Both companies are both thrilled and confident in the opportunities this acquisition brings," said Fike. "H2O has a long history of being committed to environmental safety and high-quality work, so it was essential that any partner shares the same values. We are glad to have this well-respected global marine equipment manufacturer join the H2O team."

Owens was among the first to offer USCG-certified marine sanitation devices in the 1960s, and its new line of IMO-certified units represent state-of-the-art technology in maintenance-free marine sewage treatment devices.

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Five things Gov. Hickenlooper did to put oil & gas industry ahead of Colorado’s health and water

Governor Hickenlooper likes to paint himself as an outsider, unfamiliar with the political process. But his recent actions to undermine public health, water safety – and basic common sense – have proven that Gov. Hickenlooper has become the ultimate insider – adept at helping his billion dollar oil and gas industry boosters cheat the rules, while playing the role of concerned official.

While Governor Hickenlooper has said the he’ll increase fines and hold polluters accountable, behind closed doors he’s actually been working hard to kill or weaken legislation aimed at doing just that.

Case in point: Governor Hickenlooper announces both his campaign for Colorado to be the healthiest state and safe drinking water week, then days later he successfully killed legislation to help protect water from toxic oil and gas spills.

Here’s are the FIVE THINGS Gov. Hickenlooper did to put the public health and water of Coloradans at risk and to make it easier for oil and gas companies to pollute.

Issued the weakest water testing rules for oil and gas operations in the nation…with huge carve out for Anadarko and Noble.
In January, Governor Hickenlooper’s oil and gas commission put forth weakest in the nation water testing rules –which included the Anadarko-Noble loophole for two of the biggest oil and gas operators in Colorado and Weld County – and two of the state’s biggest oil and gas polluters.
The Anadarko-Noble loophole makes it easier for billion dollar oil and gas companies to pollute water in an area in Northern Colorado that’s home to more than 25 percent of  Colorado’s oil and gas wells and more than half of the most recent spills reported.
The result is that it’ll be harder to detect water contamination and to figure out which well(s) are the source of contamination in the region that needs these public safety standards the most. In 2012, industry reported 402 spills in state, of which 20 percent resulted in water contamination, and just last month, a huge spill near Parachute creek contaminated nearby soil and water with cancer causing benzene.Lobbied against efforts to hold oil and gas companies responsible when they pollute Colorado communities and water with toxins, waste.
Governor Hickenlooper sent his lobbyists to the Capitol to weaken fines for oil and gas companies who pollute, despite the fact that Colorado has the lowest in the nation fines and a well-documented problem of spills and water contamination.  In 2012, 20 percent of all reported oil and gas spills resulted in water contamination and just six companies were responsible for more than 85 percent of all spills. And the Parachute spill – which has contaminated nearby water and soil with cancer causing benzene is now being investigated by the EPA’s criminal investigations division.Turned down money to increase the number of state oil and gas inspectors.
Governor Hickenlooper’s Department of Natural Resources agency joined up with the oil and gas industry in opposition to additional resources to help making oil and gas drilling safer by turning down money to increase the number of inspectors, from sixteen to twenty-four, for the state’s more than 52,000 wells. That’s despite the state already being short-staffed on inspectors.Successfully blocked reform efforts to make the actions of the Colorado oil and gas commission more transparent.
Governor Hickenlooper, along with the oil and gas industry, opposed legislation that would have made important systemic changes to Colorado’s oil and gas commission – the Natural Resources Department testified against the bill. Oil and gas companies currently serve on the commission, which regulates their activities, a direct conflict of interest.Worked to defeat public health study to see if fracking is making Coloradans sick.
Governor Hickenlooper’s chief of public health and the environment, Dr. Chris Urbina, testified against a health study – supported by local residents and medical professionals – that would help figure out if Coloradans who live near fracking are getting sicker than those who don’t live near fracking.

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Halliburton Launches New Recycling Service for Fracking Water

Halliburton announced the commercialization of its H2OForwardSM service. The new technology allows customers to recycle waste streams of produced water for use in well completions.

A part of Halliburton's Multi-Chem business line, the Water Management Solutions group formulates stable fracture fluids that have the ability to work with any waste stream, including water containing total dissolved solids (TDS) with values as high as 285,000 parts per million, for use in hydraulic fracturing operations.

"The H2OForward service provides a cost-effective customer solution that combines chemistry and innovative engineered technology," said James Archer, vice president of Halliburton's Multi-Chem business line.

"The product offerings from Water Management Solutions, including the CleanWave system and CleanStream service as well as our advancements in high TDS fluids are part of Halliburton's investment to further the sustainable development of the oil and gas industry," said Archer.

The new integrated service delivers technological advancements in fluid chemistry, water treatment and scale inhibition by using Halliburton's CleanWave system to treat the water, customizing both slickwater and crosslinked fracture fluid systems to work effectively with the high-TDS produced treated water, and reducing liquid biocides with Halliburton's CleanStream service technology.

"We believe the H2OForward service, especially the high-TDS fracture fluid formulations, is a paradigm shift that negates the use of fresh water and meets the supply chain needs of the customer," said Halliburton Global Strategic Business Manager – Water Management Solutions Walter Dale.

"This is no longer a technical issue; this is a function of logistics. Customers can now use produced water on unconventional wells with no loss of well productivity at a net economic benefit while minimizing the overall environmental impact," said Dale.

To date, Halliburton has completed more than 60 wells and 280 fracturing stages in the Permian and Bakken using its H2OForward services approach.

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Aquatech to Operate Water Treatment Facility for Shale Producers

Aquatech, a world leader in wastewater treatment recycle and reuse, has been granted a permit to operate a central treatment facility in Tioga County, Pennsylvania. The facility, designed using Aquatech's MoSuite set of technologies, will deliver a menu of wastewater treatment and recycle services to the regional shale gas producers and is accepting customer orders.

MoSuite is an effective combination of MoTreat and MoVap process units, a pretreatment and distillation evaporator specifically designed to treat drill fluids, frac flowback, production brine and other wastewaters from exploration and production of conventional and unconventional oil and gas. The suite of processing units delivers a tiered menu of services including filtration, disinfection, solids handling, pretreatment and evaporation concentration.

Aquatech's offering at the Tioga facility will provide high quality wastewater treatment that delivers consistent treated water quality and flexible water management solutions for the industry.

Michael Nawrath, Aquatech's sales manager said, "We bring safe and reliable technology solutions to deliver cost sustainable water management that is adaptable to the ever changing needs of the gas producers in the region."

Founded in 1981, Aquatech is based in Canonsburg, Pennsylvania, which is in the heart of the Marcellus Shale region. Aquatech's distillation evaporator and crystallization technologies treat all levels of shale oil and gas water and wastewater including high total dissolved solids (TDS) production brine. Globally, the company treats nearly 1,000,000 barrels of oil and gas field produced water per day, helping producers minimize the amount of fresh water used in the well development process and significantly reducing the volume of wastewater that must be disposed or treated off-site. This approach alleviates the burden on local water resources during shale gas exploration.

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Chesapeake Energy to Host EPA in Study of Fracking Risk to Water

WASHINGTON--Natural gas producer Chesapeake Energy Corp. (CHK) has agreed to let the Environmental Protection Agency conduct extensive tests at one of its drilling sites as part of an investigation into the safety of hydraulic fracturing, an administration official said.

The testing, which will involve water sampling before and after drilling takes place, will serve as a cornerstone of a yearslong EPA study to determine whether the process known as fracking poses a risk to water supplies.

Another natural gas company, Range Resources Corp. (RRC), also may allow the EPA to work at one of its drilling sites, although an agreement has been held up by researcher liability concerns at a drilling site, a Range Resources spokesman said.

The moves suggest companies believe they can pass close inspection by government scientists and hope cooperation will lead to a favorable view of fracking in the closely watched EPA study, which is due next year and is seen by both sides as having a major effect on the future of natural-gas drilling in the U.S.

The EPA says its study also will include sites where contamination has already been reported, including drilling projects by Pioneer Natural Resources Co. (PXD), Denbury Resources Inc. (DNR), Cabot Oil and Gas Corp. (COG), and others.

But some of the most important work involves before-and-after testing of water quality and Chesapeake's participation will give the agency access to an active drilling project.

The EPA, which earlier expressed concern that such studies couldn't be completed in time for next year's report, now is expressing more confidence. An agency official said the results will be included so long as work starts before the spring.

Chesapeake, the second-largest U.S. gas producer after Exxon Mobil Corp. (XOM), and the EPA are "very close" to settling on a location and a start date, the official said. A spokesman for Oklahoma City-based Chesapeake declined to comment.

"The value of these tests is that they are really the first independent review of what's happening from start to finish. It is a data set that doesn't really exist right now," said Briana Mordick, a scientist at the Natural Resources Defense Council.

However, Glenn Miller, a University of Nevada, Reno, professor of environmental science who studies water issues, said the EPA's test results should be taken with a grain of salt.

"If a company knows they're being followed closely, they're going to be very, very careful," Mr. Miller said.

U.S. production of natural gas has surged following advances in technology that allow energy companies to extract the fuel from hard-to-reach spots. In fracking, drillers pump a mix of water, sand and chemicals deep underground at high pressure to break apart energy-rich rocks and allow gas and oil to flow to the surface. The technique, used in many onshore drilling projects, is essential to harvesting huge oil and gas deposits trapped in shale.

The boom in production has stoked fears of water contamination. Some environmental groups, such as the Sierra Club, have called for stringent new controls.

Several natural-gas companies already test water supplies before they start to drill to establish existing conditions in case they are later accused of contaminating the water. Duke University researchers also are testing water samples in areas where drilling is likely to occur to perform before-and-after analysis.

The EPA declined to identify the location of the Chesapeake drilling site. The agency had said in December it had planned to do testing at a Chesapeake project in Louisiana's DeSoto Parish, but scheduling conflicts forced it to abandon those plans.

"We're confident in the science and the facts, and that [the EPA] will reach the same conclusions as everyone else," said Matt Pitzarella, a spokesman for Fort Worth, Texas-based Range Resources.

Range Resources "would very much like to work" with the EPA, Mr. Pitzarella said. While there is a holdup related to liability waivers for EPA employees at the site, "we're confident that we can reach an agreement," he said. Range Resources has been looking at letting the EPA conduct tests at a site in Washington County, Pa.

In 2010, the EPA accused Range Resources of causing natural gas to seep into water wells near some of its gas wells in North Texas, but it dropped the claim last year. The EPA is still working on a study of natural gas drilling in Pavillion, Wyo., after the site producer, Encana Corp. (ECA, ECA.T), and other government agencies challenged a 2011 draft EPA report that suggested a link to water contamination at Pavillion.

-Daniel Gilbert contributed to this article.

Copyright (c) 2012 Dow Jones & Company, Inc.

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Good Luck Trying to Figure This One Out: Is Shallow Water Drilling Banned, Or Not?

Joe Schoffstall Thursday, June 3, 2010 - 11:41am Tweet Earlier on Thursday, an e-mail from the Minerals Management Service's (MMS) supervisor of field operations for the Gulf of Mexico, said that drilling would be stopped in shallow waters in the Gulf due to the recent oil rig explosion.Now, the Interior Department has denied this. A spokesman from the department said "shallow water drilling may continue as long as oil and gas operations satisfy the environmental and safety requirements Secretary [Ken] Salazar outlined in his report to the President and have exploration plans that meet those requirements. There is no moratorium on shallow water drilling", according to the Washington Post.Kendra Barkoff, a spokeswoman for Interior Secretary Ken Salazar told the AP "There is a six-month moratorium on deepwater drilling," Barkoff said in an e-mail Thursday. "Shallow-water drilling may continue as long as oil and gas operations satisfy the environmental and safety requirements Secretary Salazar outlined in his report to the president and have exploration plans that meet those requirements. There is no moratorium on shallow water drilling."In essence, shallow water drilling was declared banned until further notice, but not really. It get's a tiny bit more confusing.A regional supervisor of the MMA Gulf region told one company looking to obtain a permit that"until further notice we have been informed not to approve or allow any drilling no matter the water depth,"The weird thing noted by WaPo was just three days before the e-mail exchange, the supervisor told the same company that the Obama moratorium would not affect drilling in water up to 500 feet.I guess the real question is: Does anyone know what's really going on? Highly unlikely. View the discussion thread. More Author PostsMost Popular Egypt's Morsi, North Korea's Kim Jung Un Lead Early Voting For Person of the Year 1 week 6 days ago Chris Matthews Ecstatic Hurricane Sandy Devastation Helped Obama 4 weeks 5 days ago Certified GOP Poll Watchers Allegedly Turned Away in Florida 4 weeks 6 days ago Obama Mural Painted Within Polling Station In Philadelphia 4 weeks 6 days ago Black Grassroots Activists Protest Obama Fundraiser, City Hall, ABC News In Chicago 5 weeks 7 hours ago Bill Clinton: 'You should care whether your president is telling you the truth' 5 weeks 21 hours ago Mitt Romney Will Win The Election, According To The 'Redskins Rule' 5 weeks 1 day ago Allen West Publicly Scolds Media Tracker At Vietnam Memorial Service 5 weeks 6 days ago Criminal Investigation Launched After Jim Moran Undercover Video 6 weeks 4 days ago EPA Designates Millions More Towards 'Environmental Justice' 7 weeks 3 days ago

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