Study: Filtration a Viable Option for Produced Water from the Marcellus Shale

The rising production of natural gas from hydraulically fractured wells in Appalachia generates along with it contaminated produced water that must be carefully disposed of. Researchers at Pennsylvania State University say that producers would be wise to consider the environmental risks associated with the most commonly used disposal practice of underground injection, and instead adopt more environmentally friendly and sustainable innovations in water filtration.

The study, Sustainability in Marcellus Shale Development, published by Penn State’s College of Engineering in conjunction with Chevron, notes that produced and flowback water from the prolific Marcellus Shale in Pennsylvania is most commonly disposed of through injection into saltwater injection wells drilled far below the deepest known aquifer.

But although this method is the cheapest available and most frequently used, it brings with it the potential for surface spills and casing leaks that can contaminate freshwater, as well as the risk of activating dormant faults and causing earthquakes.

Disposing Fracked Water

“During the hydraulic fracturing process, water and chemicals are used to stimulate the fissures in the rock in order to extract the natural gas. Water is mixed with sand and other chemicals and then injected into the well. After creating cracks in the Marcellus Shale, flowback water, a brine solution with heavy metals and chemicals, quickly comes back. Typically, this flowback water is stored in tanks or pits before treatment, recycling, or disposal,” according to the report, co-written by Kyle Bambu, Mike Spero, and Harry Polychronopoulos.

The most common way to dispose of this produced water is by pumping it into saltwater disposal wells that are drilled hundreds below the deepest known aquifers. But Pennsylvania’s unique geology is not well suited for such wells. At the time the study was published in Fall 2016, there were 144,000 Class II injection wells in the US and only eight of them were Class II salt water disposal wells in Pennsylvania. These eight wells combined accepted 8,667 barrels per day of brine, while similar wells operated in Texas can each dispose of more than 26,000 b/d of brine.

According to the report, the average cost to dispose of one bbl of fluid can range from as low as 25¢/bbl if the oil company operates its own disposal well, to anywhere from 50¢/bbl to $2.50/bbl if a commercial saltwater disposal well is used. The cost of using disposal is further increased by the cost of transportation.

“In northern Pennsylvania, where commercial disposal wells aren’t plentiful, the brine water may have to be transported to Ohio or West Virginia. This can increase costs by $4.00 to $6.00 a barrel, bringing the net cost of disposal in the Marcellus Shale region to $4.50/bbl to $8.50/bbl,” the study said.

The use of underground disposal wells is not without risk, and frequent concerns include the potential for groundwater contamination and induced seismic activity. In Youngstown, Ohio, the researchers noted that a Class II disposal well for fracking wastewater was linked to seismic activity after it activated a previously unknown fault line. That well was blamed for 10 minor earthquakes, the largest of which is a magnitude of 3.9. A spate of earthquakes in Oklahoma in recent years has likewise been linked to the increased injection of water into disposal wells.

The need to dispose of produced water in Pennsylvania has become more pressing in recent years as natural gas production from the prolific Marcellus and neighboring Utica shales has taken off.  Data from the federal Energy Information (EIA) Administration show that output from the shale formations more than tripled Appalachian gas production from 7.8 billion cubic feet per day in 2012 to 23.8 Bcf/d in 2017 (EIA). These plays are credited for driving growth in US natural gas production since 2012 and have played a critical role in enabling low domestic prices and increasing exports.

The Water Filtration Alternative

Researchers note that a number of alternatives to disposal wells are emerging at varying levels of cost. These largely involve treating the produced water to remove its various contaminants, which can include radioactive substances, heavy metals, and high concentrations of salt. Traditional wastewater treatment plants cannot be used because they lack the sufficient processes needed to clean this water.

The most cost competitive alternative to underground injection highlighted by researchers is the option of using a membrane to clean the brine produced water. The company Oasys Water offers a system that drives the brine solution through a series of semi-permeable membranes at a cost of nearly $2/bbl of water. The water that emerges from this process is clean enough to be discharged into streams or drainage systems.

Other potential treatments on the horizon that require further research include the option of boiling the water. However, researchers note that the cost of using this process can run upwards of $17/bbl and the heavy salt causes extreme wear and tear to the requisite industrial boilers, resulting in massive equipment replacement costs.

Lastly, the study says the process of electrodialysis could be used to separate water from contaminants. Researchers at the Massachusetts Institute of Technology have found that an electrical current can be used to separate fresh water from a salty solution. Salt is an effective conductor of electricity and successive stages of electrodialysis can remove most contaminates. But this process has not been tested in the oil and gas industry and there are not commercial treatment options available.

Researchers ultimately concluded that while the common practice of injecting produced water into disposal wells is relatively cheap, this practice comes with high environmental risks. These risks include the potential for groundwater contamination that is caused by surface spills or breaks in the tubing for saltwater disposal wells and even induced seismic activity.

At present, the impetus for improving produced water disposal practices is driven primarily by the sustainability practices of each producer and not government regulations. Researchers found that the oil and gas industry is exempt from some of the most stringent federal environmental regulations, like the Safe Drinking Water Act the Clean Water Act, but noted that states have been working to impose their own rules to address areas of concern. For instance, Pennsylvania in recent years adopted new guidelines intended to prevent spills and releases of harmful substances.

Today’s Best Option

The study ultimately recommends Oasys Water’s membrane filtration as the best option for disposing of produced water today. Researchers said that while using this method can result in slightly higher costs for water treatment and transportation, it appears to be the most sustainable solution until other technological advances are advanced in the future.

“This (membrane) system was recommended because of its relatively cheap cost yet adherence to sustainability and environmentally friendly concerns,” the study said.

To read a PDF of the Penn State study, click here.

Rethinking the oil and gas organization

December 2016, McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.

Organizational choices made during a time of resource scarcity need reexamination when the cycle turns.

When business cycles turn, cyclical industries can struggle to retool their organizations for the new environment. For instance, today’s oil and gas companies were developed in a time of resource scarcity. To get at those hard-to-find, difficult-to-develop resources, companies greatly expanded the role of their central functions—mandating them to set common standards, make technical design decisions, track company-wide metrics, and disseminate best practices. This worked well during a decade of high growth and high prices but created complexity that added costs, stifled innovation, and slowed down decision making. As these central teams expanded, general and administrative costs grew fivefold, hitting nearly $5 per barrel in 2014 (exhibit), with the biggest increases coming from technical functions such as engineering, geosciences, and health and safety.

Oil companies have cut support functions since 2014 but must consider more radical organizational changes as prices remain weak.

With prices now below $50 a barrel, that organizational blueprint is no longer sustainable. While companies have cut their support functions since 2014, the overall organizations supported by these functions are also smaller. This suggests further reductions in corporate functions will be needed, as well as new organizational models.

A more agile organization, with fluid teams and looser hierarchies, can lower costs and create greater responsiveness to today’s vastly different markets—ranging from megaprojects to less asset-heavy unconventional shale-oil and renewable-asset plays. Technologies such as networked sensors that generate and share data can help optimize production processes, while digitally enabled automation of routine manual activity can reduce human risk and spur productivity. Critically, the structures built to manage scarce talent and large-scale megaprojects will need to be fundamentally redesigned. We see two models arising: for lower-risk assets such as tight oil, a very lean corporate center with highly autonomous asset teams will suffice, while higher-risk, more capital-intensive assets will need a comparatively stronger center with deeper functional and risk-management capabilities.

For additional insights, see “The oil and gas organization of the future.”

About the author(s)

Christopher Handscomb is a partner in McKinsey’s London office, Scott Sharabura is an associate partner in the Calgary office, and Jannik Woxholth is a consultant in the Oslo office.

Innovations Improve Drilling Accuracy and Efficiency Leading to Increased Well Output

By Luis Gamboa, Oil & Gas Business Development Manager, Rockwell Automation

In late November, Nabors Drilling, the largest land drilling rig contractor in the world, invited a few members of Rockwell Automation staff and the media down to Houston, Texas, to see the latest innovations they’ve made in drilling automation to improve drill time, accuracy and efficiency while enhancing worker safety.

Our tour included a look at the services Nabors provides to support rig operation remotely, new software solutions Nabors is engineering to automate drilling navigation, and a visit to a rig build site to tour a SmartRig™.

The Services

The first stop on our tour was the Rigline 24/7™ operations center: a glass-walled area where expert technicians remotely monitor the status of hundreds of drilling rigs in operation all over the globe.

The technicians can view KPIs like rate of penetration, directional path, weight on the drill bit, torques, fluid flow rates and various other parameters throughout all phases of the well construction process.

We visited the largest land drilling rig contractor in the world to see how they are using the latest technology.

They watch for alerts of rig issues, answer phone calls from rig operators who have questions, and intervene if a “red-status” is created. The Rockwell Automation FactoryTalk® suite of information solutions is used to capture all the rig data in real time, and contextualize and display it as useful information.

The level of expertise the staff can provide from afar is impressive – some of the rigs are even equipped with video cameras in key places to provide visual insight in addition to the data coming in from the controllers on the rig. This allows experts to operate the rig remotely from Houston, if needed.

The Software

Next, we stopped down in the software simulation area to learn about the software Nabors has developed to automate navigation, including directional drilling. Nabors sought to fix an industry issue that was causing extra expense and downtime during the drilling process: the need to bring an experienced directional driller on-site when it was time to execute a slide, and the variability associated with relying on human operation.

In the software simulation area, Nabors has a full drilling operator station set up so engineers can test the constraints of this new software, and also to allow for operator training on how to use it. We got a peek at the ways Allen-Bradley PACs and motor control centers are powering the drilling equipment and feeding data to the software to help automate control of the rig equipment and enable this more efficient and accurate drilling.

The Rig

Finally, it was time to drive 40 minutes over to Crosby, Texas, to see a Nabors SmartRig in person. The rig stood an impressive 90 feet tall, with the platform, operator cab, and e-house standing 45 feet in the air.

The rig we saw was a walking side-saddle design, with automated pipe racking capability: which means the pipe can be racked without any human intervention off on the side of the rig.

When drilling a multiwell pad, the entire rig can be walked in any direction to drill the next well without needing to disassemble or move the racking equipment out of the way.

We’re getting closer to seeing completely automated, remotely monitored drilling rigs – which opens up a ton of possibilities.

The modular rig design allows Nabors to rig down and move all the equipment to the next drilling site in as little as 36 hours. Nabors next iteration of the SmartRig, which they’re branding as the iRig, will have a robotic arm that completely automates movement of rig floor equipment and pipe through Rigtelligent™ controls, powered by Rockwell Automation.

It was interesting to see the innovative ways Nabors has leveraged the capabilities of MCCs, PACs and software to automate the well drilling process. The industry is taking giant leaps forward, and we’re getting closer to seeing completely automated, remotely monitored drilling rigs – which opens up a ton of additional possibilities to reduce drilling cost, improve drilling operations and safeguard workers.

For more information on the work Nabors is doing, visit their website. And to learn more about the ways Rockwell Automation technology is supporting greater efficiency and innovation in the oil and gas industry, visit the oil and gas section of their website.

OGCI Invests in a Diverse Set of Technologies Designed to Reduce Emissions

The Oil and Gas Climate Initiative is advancing efforts to develop and commercialize technologies that reduce greenhouse gas emissions in some unexpected areas.

The voluntary organization of 10 major international oil and gas producers has finalized the first three investments of its billion-dollar investment fund, OGCI Climate Investments, to fund three low-emission technology projects.

The projects, the first in a host of planned investments, seek to make more efficient engines, reduce the environmental impacts of cement, and demonstrate the commercial viability of carbon capture and storage at a gas-fired power plant.

“OGCI Climate Investments’ goal is to deliver GHG reductions by investing in pre-commercial technologies and solutions that are both cost-effective and will scale globally,” explained OGCI Climate Investments Chief Executive Officer Pratima Rangarajan.

The group also has the unique ability to deploy the technologies in the operations of its member companies to amplify the scale an impact of its initial investments.

Promising technologies

The investments include US-based cement and concrete production company Solidia Technologies, which has patented a technology that facilitates the production of cement in a way that generates fewer emissions and uses CO2 rather than water to cure concrete.

OGCI says Solidia’s technology has the potential to lower the carbon footprint of concrete by up to 70% and water consumption by up to 80%. The project is also expected to demonstrate how carbon dioxide can be commercially re-used in an environmentally sound way.

In the OGCI report Catalyst for Change, the organization notes that the conversion of captured carbon dioxide into useable products can help reduce greenhouse gas emissions in specific sectors. In fact, the report notes that OGCI is looking to “invest in a range of companies that have developed innovative and commercially viable carbon utilization technologies.”

Another recipient of OGCI funding is Achates Power, a company that is developing high-efficiency opposed-piston engines that have the potential to reduce the greenhouse gas emissions produced by vehicles.  Achates Power plans to use the funds to accelerate the deployment of its technology across the globe alongside a broad consortium of engine makers.

The third project aims to design the world’s first full-scale natural gas power plant with carbon capture and storage, including industrial CO2 sequestration capability. OGCI Climate Investments has acquired the concept for a project in the UK and plans to work with the project team on a commercially viable concept and basic engineering design that can receive government support and attract private sector investors.

The project would also “enable neighboring energy-intensive industries to leverage the carbon dioxide transport and storage network that would be developed. This way, they too would be able to eliminate a large share of carbon dioxide from their operations,” OGCI said it its report.

The project could also advance the UK’s plans to reduce its greenhouse gas emissions to 80% of baseline 1990 levels by 2050.

The driving force behind OGCI

Together, OGCI’s 10 member companies claim to account for more than one-fourth of global oil and gas production. Their efforts demonstrate a commitment by these top producers – which include several national oil companies – to lessen the environmental impact of fossil fuels and collaborate on actions to reduce emissions.

The roster of members includes BP, China National Petroleum Corp., Eni, Pemex, Repsol, Saudi Aramco, Shell, Statoil and Total. An eleventh member, Brazil’s Petrobras, is set to formally join the group soon.

By collaborating thorough OGCI, the producers aim to be a catalyst for across the oil and gas industry and beyond. Since they produce so much of the world’s energy, the report says that makes them “important players in ensuring the supply of reliable and affordable energy, and gives us the opportunity to advance the transition to a low-emissions future.”

US Producers Reveal More Details on Their Methane Oversight Programs

Many top upstream and midstream companies in the US oil and gas sector are making meaningful methane disclosures to address increasing investor concerns about the gas, according to a report by the Environmental Defense Fund.

The EDF report, The Disclosure Divide: Revisiting Rising Risk and Methane Reporting in the U.S. Oil & Gas Industry, found that nine of the top 64 upstream and midstream companies release comprehensive reports on their methane leak detection and repair programs (LDAR), with many of the remaining companies carrying out some form of methane management program.

“Bright spots in the report include Southwestern Energy, which not only has a quantitative target, but is also committed to continuous improvement,” the report found. Noble Energy was also highlighted for releasing extensive details on its LDAR program in the Denver Julesburg Basin, the Appalachian Basin and onshore Texas.

“Noble’s methodology for inspections is conducted with infrared cameras. These efforts are reported as contributing factors to Noble Energy’s 1.62 billion cubic feet (bcf) reduction in methane emissions in 2016,” the report said.

Top performers also included shale-focused US producers Consol Energy, EOG Resources, Hess, Noble Energy, and WPX Energy as well as diversified international players ConocoPhillps and ExxonMobil and North American pipeline giant TransCanada.

To receive the highest distinction, each of the companies had to disclose three key details about its LDAR program, namely: The scope of the program, the frequency of inspections, and the methodology used for methane detection.

EDF noted that LDAR is evolving rapidly with emerging technologies like continuous mon­itors being piloted by Shell and Statoil, drone-based monitors, and predictive analytics.

Methane, a key component of natural gas, is a greenhouse gas 84 times more potent than carbon dioxide that is linked to climate change, according to EDF.

Activist Shareholders Push for Disclosures

The increased disclosures come as the Trump administration is rolling back aggressive methane-reduction regulations written by the Obama administration’s Environmental Protection Agency and Interior Department, measures that were criticized by the oil and gas industry for the complexity and high cost of compliance.

Regardless, the focus on methane emissions is unlikely to abate as a growing number of investors are pressuring oil and gas companies to increase their environmental disclosures. The EDF report found that five of the seven companies that began offering more details on their LDAR practices in 2017 were targets of methane-shareholder resolutions during the past two years.

EDF bloggers Kate Gaumond and Sean Wright note that 390 investors representing more than $22 trillion in assets have signed a letter supporting the Task Force on Climate-Related Financial Disclosures, an organization that advocates for a unified set of recommendations for corporate climate disclosure.

Among those calling for these measures is CalSTRS, California’s second largest public pension fund. “As a long-term global investor, we recognize that methane emissions are one of the most financially significant environmental risks we face,” Brian Rice, portfolio manager at CalSTRS said in a press release.

The push appears to be working. Cimarex Energy started providing more information about its methane management practices after it received methane shareholder resolutions in 2016 and 2017. ExxonMobil has likewise been the target of similar shareholder action and last year unveiled a comprehensive methane emissions reduction program focused on its shale-focused subsidiary XTO Energy (SO Jan. 28’18).

Industry is Leading its Own Efforts

The oil and gas industry has created its own group to address environmental concerns. In December, a host of players joined with the American Petroleum Institute to create a partnership designed to reduce the environmental impact operations across the US (SO Dec.24’17).

The voluntary effort, called the Environmental Partnership, is comprised of 26 producers who have pledged to initially focus on reducing emissions of methane and volatile organic compounds (VOCs) from their operations.

The move is as a step in the right direction, though many environmental advocates would still like to see more.

“EDF looks forward to working with leading companies and other stakeholders to support methane regulations that build from and improve upon federal and state regulatory models and ensure that we are tapping all cost-effective solutions to comprehensively address oil and gas methane emissions,” EDF business director Ben Ratner said in a press release.

Chevron Uses Recycled Water to Boost Production at Aging California Oil Field

Chevron is using a sophisticated water treatment system to clean up produced wastewater at a Southern California oil field and using that recycled water to boost recovery from a previously idled portion of the field – demonstrating along the way that what’s good for the environment can also be good for a company’s bottom line.

The Optimized Pretreatment and Unique Separation (OPUS) system was installed at the San Ardo oil field by water treatment company Veolia a decade ago and the company continues to oversee it today.  The installation is the first of its kind to use the OPUS system as part of a produced water desalination facility and the cleaned up water is either used in steam flooding operations or safely disposed of on the surface.

San Ardo is one of the most prolific fields in California. It was initially discovered in the late 1940s and has been producing for decades. State data shows that it was pumping 21,400 barrels of oil per day in 2015, earning it the designation of being California’s eighth producing oil field. Output has actually been ticking upward annually since the OPUS system was put into place, with state data showing oil output in 2015 was nearly double production of 11,400 b/d recorded in 2008.

To counter natural production declines, the aging field has been using steam flooding since the 1960s to soften the remaining oil and coax it out of the ground.  During this process, large volumes of water rise to the surface that must later be treated and disposed of. In fact, for every barrel of oil produced in 2015, state data show about 15 barrels of water rose to the surface as well – or an average of 328,000 b/d of water per day.   

A case study by Veolia says, “Historically, a portion of this water had been recycled and softened to provide water for steam generation, with the (rest) going to local EPA class II injection wells for disposal. However, the injection zone capacity is limited and that had constrained full field development.”

That’s where to OPUS system comes in to make up the difference and ease water constraints. OPUS cleans up about 50,000 bb/d of water that using a multiple-treatment process that takes out contaminants and removes 92% of total dissolved solids.

With the treated water clean enough for reuse, the limited capacity of the injection wells becomes is less of a limiting factor in operations. The recycled water that is not used to generate steam is clean enough to meet California’s strict effluent discharge requirements and can be released through shallow wetlands into aquifer recharge basins that replenish water resources.

Veolia says the project goal was to reduce the total dissolved solids (TDS) of the feed water to less than 6,500 parts per million (pps), and the boron to less than 0.64 ppm for discharge, while achieving 75% water recovery across the treatment system and minimizing the volume of produced water. “For steam generation, the project goal was to reduce the feed water hardness to less than 2 ppm total hardness as CaCO3,” the case study said.

The system’s daily operations are overseen by Veolia, and Veolia staff also provides onsite and offsite technical and engineering support to troubleshoot issues as they arise. In short, they are responsible for ensuring that optimal function is maintained at the site.

The team displayed noteworthy ingenuity in 2005 and 2008 when a shortage of hydrochloric acid arose after powerful hurricanes pummeled the US Gulf Coast. OPUS uses hydrochloric acid in the regeneration process of the water softeners that are a part of the system. To get around this issue ad keep operations rolling, Veolia staff came up with a different concentration that lowered the field’s reliance on hydrochloric acid.

Indeed, the OPUS system is demonstrating one of the ways that producers can use technology and ingenuity to make their operations more environmentally responsible. To read the full case study on Veolia’s San Ardo project, click here. https://www.veolianorthamerica.com/en/case-studies/san-ardo-refinery

Southern California Refinery Case Study
PDF – 2.12 MB

 

Caterpillar Showcases Emissions Conscious Oilfield Drilling Technology

 

Learn about the Cat 3512E Tier 4 Final Land Electric Drive Drilling Module with Diana Hopkins, the land drilling and production marketing manager for Caterpillar Oil & Gas. The module uses NOx reduction systems and a simple diesel oxidation catalyst to reduce emissions.

Video via Caterpillar Inc. and Youtube.

First-of-its-Kind Solar Installation to Power California Heavy Oil Project

One of California’s largest oil and gas producers is preparing to build the state’s biggest solar energy project at an oilfield near Bakersfield.

Aera Energy is teaming up with GlassPoint Solar to build the project at the Belridge oil field. Once complete, it will be the first installation of its kind in the world to use solar steam and solar electricity to power oilfield operations. The installation is expected to save more than 376,000 metric tons of carbon dioxide emissions per year, offsetting the equivalent of 80,000 cars, more than one-third of the cars in Bakersfield today.

“Our partnership with Aera demonstrates the growing energy convergence where renewables and traditional energy leaders are working together to address some of the biggest challenges of our time,” said Sanjeev Kumar, senior vice president of Americas for GlassPoint.

Once complete, Aera says the Belridge Solar project will deliver the largest peak energy output of any solar plant in California.

The installation will consist of an 850 MWt solar thermal facility that will produce 12 million barrels of steam per year and a 26.5 MWe photovoltaic facility to generate electricity. The combined solar-generated steam and electricity will reduce the amount of natural gas now being used onsite for oilfield operations.

“Aera is committed to safe, responsible operations and is thrilled to extend our environmental leadership by using solar to power our production. Adding solar energy at Belridge allows us to continue to lead the way in the safest, most environmentally responsible energy extraction there is,” said Aera Energy President and Chief Executive Officer Christina Sistrunk.

Belridge is a heavy oil field which requires the injection of steam into the reservoir to heat the oil so that it can be pumped to the surface. This process, known as thermal enhanced oil recovery (EOR), typically generates steam using natural gas. By using the thermal energy of the sun to replace the combustion of natural gas, GlassPoint’s technology will allow Area to reduce its energy consumption and carbon footprint at Belridge.

The planned facility at Belridge will reduce NOx and other local pollutants, improving air quality in the San Joaquin Valley, one of California’s most challenged air districts.

California is the third-largest oil producing state in the US, with 2016 output of 510,000 barrels of oil per day, according to data from the US Energy Information Administration. Heavy oil fields like Belridge account for half of the state’s crude oil production.

Aera is one of California’s largest producers, and it is responsible for 25 percent of the state’s oil and gas production. The company expects to break ground on the Belridge Solar plant in the first half of 2019. The project is slated to start producing steam and electricity as early as 2020.

Glass Point says the oil and gas industry is a prime market for renewables because it consumes up to 10% of its own energy projection. Glass Point unveiled its first commercial solar oilfield project in 2011 with Berry Petroleum in California’s Kern County and now has more than 1 gigawatt of solar oilfield projects under construction around the globe. Last year, the company was recognized by the World Economic Forum as a 2016 Technology Pioneer for its role in enabling more economical and sustainable oil production.

“By harnessing the power of the sun to produce oil, oil operators can efficiently reduce emissions using advanced technology, creating long-term benefits for the local economy and environment,” senior vice president Kumar said.

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