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January 2016 - Issue 7
Welcome to the Battelle Oil & Gas Newsletter. We put this together as a service to our friends in the oil and gas industry keep you informed of the latest news from our scientists and engineers and the industry.
Battelle works with oil and gas companies and others to advance the industry with the latest science and technology. Battelle Oil & Gas will keep you up-to-date on cutting edge technologies, services and processes.
How much brine can be stored in the Northern Appalachian Basin, and where are the safest places to inject? Oil and gas operators in Ohio, West Virginia and Pennsylvania now have clear answers for safe, economical brine disposal decisions.
Growth in shale gas production in the Appalachian region has led to increased demand for brine and flowback water disposal options. In 2013, the Research Partnership to Secure Energy for America (RPSEA) contracted with Battelle to lead an investigation of the geologic storage capacity of the Northern Appalachian Basin in order to develop a geologic and operational framework for brine disposal. Research was completed in 2015, and results are now available in a new technical report from RPSEA. The report details storage capacity and geotechnical suitability in the main injection zones throughout the region to help oil and gas producers identify the most economical, geographically convenient and safe geologic storage locations for brine disposal.
The project—conducted in partnership with Kentucky Geological Survey, NSI Technologies, Ohio Division of Geological Survey, Pennsylvania Bureau of Topographic and Geologic Survey, West Virginia Geological and Economic Survey, and Ohio Oil Gathering Corporation—studied geotechnical parameters and historical operational data from eastern Kentucky, Ohio, Pennsylvania and West Virginia.
Researchers analyzed subsurface characteristics and took core samples to evaluate the permeability, strength and porosity of rock in different areas. They also looked at historical operational data in each of the studied zones. Using computer modeling and simulation, they were able to determine total storage capacity and predict the potential fate and transport of injected brine in each target area. Field research at six operating wells was used to validate the computer models.
The study determined that, overall, there is more than enough capacity to meet projected brine disposal needs for the shale gas industry for many years to come. However, some areas are more suitable for brine disposal than others. The technical report details this local information along with recommended safe injection rates and limits for each area.
How do depleted oil and gas wells impact the safety and efficacy of carbon sequestration and storage? Researchers at Battelle recently completed a comprehensive analysis of historical oil wells in Ohio and Michigan to determine how they impact CO2 storage risks in different areas of the states. The data is now available as a map to help stakeholders in the oil & gas and power industries pinpoint the areas most likely to be viable for carbon storage.
There are over one million depleted oil wells throughout the Midwestern United States, some dating back to the mid 1800s. Many of these wells are located in areas where power companies and other carbon-intensive industries would benefit from using carbon capture, utilization and storage (CCUS) methods to reduce their carbon footprints. However, little was known about the current condition of these wells and how their condition changes over time. Degraded wells can act as conduits to allow carbon injected into local reservoirs to escape back into the atmosphere.
The three-year project, funded by the Department of Energy (DOE) and completed in partnership with BP and Columbia NiSource, examined historical logs and records—including construction and operational data and geophysical logs—to complete a survey of depleted wells in Ohio and Michigan. Wellbore integrity testing was completed on representative wells to determine how age, material construction and other factors have impacted the studied wells. Testing included evaluation of cement degradation, cracks and microannuli, acid-gas zones, channeling and casing corrosion. Sustained pressure casing monitoring was completed for 13 representative wells.
Using this data, researchers were able to determine how different characteristics impact wellbore integrity and develop maps that correlate well characteristics and potential risks across both states. By looking at test results for the representative wells, researchers can now predict the condition of wells of similar age, material construction, depth and geologic conditions. Researchers applied this analysis to 240,000 abandoned and depleted wells in Ohio and 60,000 in Michigan to develop regional datasets that predict potential local wellbore integrity risks with a high degree of confidence.
The maps identify which zones are likely to be safe for CCUS and which zones will require mitigation to make them safe for long-term carbon storage. The analysis showed that some areas previously considered too risky for CCUS are in fact most likely safe because the wells present are not deep enough to penetrate the geologic storage zone. By contrast, analysis of wells in other areas identified the likelihood of cracks and defects that would permit CO2 to escape over time. The dataset also identifies wells with limited records that would require further characterization.
This is the first detailed analysis of wellbore integrity for wells in Ohio and Michigan. The oil & gas and power industries will be able to use the data to determine which areas are most viable for CCUS and estimate the amount of mitigation needed for safe CO2 injection and storage in their regions. Researchers at Battelle are now beginning a follow up project in Michigan to see how exposure to CO2 impacts wellbore integrity over time.
Determining the presence or absence of hydrocarbons in an area is an easy process. But when attributing the source of hydrocarbon contamination is critical, standard testing methods can fall short.
Whether faced with a possible accidental release or simply monitoring the impact of operations, source attribution is important for oil and gas developers. It’s not enough to know that hydrocarbons are present. In order to determine responsibility and liability, companies need to be able to determine whether the hydrocarbons come from their operations, those of a competitor or simply from natural sources.
See chart for more information on EPA standard methods and their limitations.
The Limitations of EPA Required Testing
The Environmental Protection Agency (EPA) has outlined specific required tests for oil and gas developers and operators. These minimum testing requirements are geared towards safety and environmental compliance, with a goal of determining whether toxic substances are present and in what quantities. They are generalized testing requirements that have not been optimized for hydrocarbons specifically; the tests simply allow the EPA to determine whether contaminants in an area present risks for human health and safety or for the environment. Designed to support compliance with the Resource Conservation and Recovery Act (RCRA), the battery of required tests are applied to all hazardous wastes, including wastewater and sludge from a variety of industrial processes.
When it comes to source attribution for the oil and gas industry, these tests have significant limitations. First and foremost, they were not designed specifically for hydrocarbon chemistry. While they are useful for initial screening, they miss some of the most abundant (and toxic) components of petroleum products. As a result, these tests are often subject to false positives or negatives and lack valuable quantitative information.
Secondly, they provide little or no diagnostic source identification. They simply do not have the precision and level of detail necessary to accurately determine what type of product is present (e.g. heavy crude vs. light crude vs. heavy fuel oil) or characterize the exact chemical makeup of a sample. This means that they are subject to interference from naturally occurring hydrocarbons and are not able to distinguish between petroleum products originating from different sources.
These distinctions become critical in the case of forensic investigations. Crude oils and refined petroleum products are complex mixtures that can contain hundreds or thousands of organic compounds. Each petroleum product will have its own unique chemical “fingerprint” depending on its exact composition, meaning that physical and chemical properties of oil from the North Slope can be very different from oil from the Gulf of Mexico. Refining methods and chemical additives lead to even more chemical differentiation between finished products.
Petroleum chemists quantify the presence of hydrocarbon chains of different lengths as well as key biomarkers, polycyclic aromatic hydrocarbons, and other chemicals and additives in order to develop a fingerprint for a specific sample. Chemists can compare the fingerprints of different samples for highly accurate product identification and differentiation. This allows them to determine appropriate source attribution and model the fate and transport of different petroleum products in the environment.
Source attribution must also take factors such as weathering, water-washing and biodegradation into account when comparing fresh samples from a source to samples collected from the environment. An understanding of how hydrocarbons weather and degrade over time and under different conditions is necessary for accurate product comparison and attribution.
Determining which tests are required for a particular project requires an in-depth understanding of petroleum chemistry. There is no “one size fits all” analytical method that is universally appropriate for all types of crude oils and refined products. The mix of analytical methods used will depend on the types of contaminants present (e.g., light distillates vs. heavy crudes) and the ultimate goals of the investigation. In cases where the types of hydrocarbon compounds present are unknown, a tiered approach that starts with basic screening before moving into more sophisticated tests may be the most cost-effective way to discover or eliminate potential contaminants from consideration.
For spill response and forensic investigations, companies need highly accurate and defensible data. Battelle has developed modified methods that improve the accuracy and precision of EPA required tests for hydrocarbon forensics. These methods are specific to petroleum chemistry and address the limitations of the standard EPA methods. Petroleum chemists at Battelle work with oil & gas customers to develop a testing protocol that meets the specific needs of the investigation.
Many companies waste time and resources by engaging in analytical tests that will not meet their ultimate needs and requirements. By understanding the strengths and limitations of different analytical methods, and selecting the right methods to meet their goals from the start, companies can control costs and speed up investigation time.
The Utica-Point Pleasant shale source bed underlies much of the state of Ohio. However, large portions of the bed are considered uneconomical for production. A new Battelle-led Joint Industry Project (JIP) has been formed to determine whether cyclic gas injection can be used to stimulate production in liquid-rich regions of the Utica-Point Pleasant shale.
The JIP (Cyclic Gas Injection for Stimulating Oil Recovery in the Liquid-Rich Regions of the Utica-Point Pleasant Shale) was formed in the fall of 2015. Participating companies will share in the cost of research to evaluate the efficacy and costs of cyclic gas injection for this region.
The Utica-Point Pleasant shale play encompasses western Pennsylvania, western New York, eastern Ohio and most of West Virginia. The most recent U.S. Geological Survey study of the Utica-Point Pleasant, released in October 2012, estimates the amount of technically recoverable oil and gas reserves at 590 million to 1.39 billion barrels of oil, 21 trillion to 61 trillion cubic feet (Tcf) of natural gas, and 4 million to 16 million barrels of natural gas liquids. In western Pennsylvania and southeastern Ohio, the play consists primarily of mature source rock, rich in dry gases that respond well to established hydraulic fracturing methods. As developers move north and west, the source rocks are less mature and the product ranges from wet gas to heavier crude oil. The heavier, more liquid product is less responsive to hydraulic fracturing and does not produce economical amounts of oil following conventional completion methods.
The JIP was formed to evaluate whether alternative completion methods could be used to increase oil production and make the area economical for oil and gas development. A large portion of Ohio lies within this oil-rich leg of the Utica-Point Pleasant shale bed. Currently, it is not economical to produce with either conventional oil & gas drilling or completion methods such as hydraulic fracturing.
Immature liquid petroleum products are heavier and less movable than their lighter gas counterparts. Because the individual molecules are larger, they cannot move through small channels and impermeable, low porosity rocks as easily. While hydraulic fracturing with large volumes of water and sand works well to release dry and wet gases, the same technique does not work well with the liquid oil products that underlie most of Ohio.
In cyclic gas injection, a gas (which could be CO2 or even gas from engine or power plant exhaust) is injected into the shale. The addition of gas affects the viscosity and mobility of the oil in the formation in order to make the oil more mobile and easier to produce. The gas injection and soak cycle is repeated several times, with production taking place between injection cycles.
The study may also evaluate other methods of oil recovery from the liquid-rich shale.
Phase I, which began in November of 2015 and is expected to run through the summer of 2016, will consist of data gathering and analysis. Battelle will perform a complete reservoir characterization of the Utica-Point Pleasant shale play in Ohio and gather production and operational data from participating JIP members. The collected data will be used to develop recommendations and proposals for the field trials.
Phase II will consist of field testing of the recommended method(s) at a well operated by one of the participating partners. It is expected to begin in the summer of 2016 and will run for 12 to 18 months.
All JIP participants will have access to all of the data and analysis that comes out of this project. The end goal is to develop a set of recommendations and best practices for extracting petroleum from the oil-rich leg of the Utica-Point Pleasant shale play that runs from northeast Ohio down through central and southeastern Ohio. This could potentially open up hundreds of thousands of acres that are currently considered uneconomical in the Utica-Point Pleasant shale play.
Current JIP participants include Artex Oil Company, PDC Energy, Inc., NGO Development Corporation, Inc., Bakerwell, Inc. and Solid Rock Energy, Inc.
Battelle is ready to begin the joint development of a new rapid field detection device for microbiologically influenced corrosion (MIC). The study is part of a joint industry research program (JIRP) to complete development of the device for use in the field by the oil and gas community. The JIRP is still open for a limited number of additional participants.
MIC causes significant damage to oil and gas pipelines, downhole equipment, offshore structures and other critical assets. Left untreated, it can lead to asset failure resulting in production delays, flow disruption or even accidental releases.
Battelle’s hand-held detection kit will allow operators and oilfield service staff to quickly identify the presence and type of corrosion-causing bacteria so that they can select the most effective remedy options. Not all bacteria influence corrosion; of those that do, different types respond best to different treatments. The MIC detection device under development uses genetic analysis to identify the presence of bacteria most commonly associated with corrosion, such as sulfur-reducing bacteria (SRB), acid-producing bacteria (APB) or iron-related bacteria (IRB).
Currently, in order to identify the species of bacteria present, operators must send samples away to a lab for DNA analysis—often waiting days or weeks for results. The new field test will allow staff to diagnose an MIC problem in the field within hours of collecting samples so that appropriate mitigating action can be started right away
Battelle’s proprietary MIC detection process consists of field-based methods for purifying DNA from bacteria present in a range of oil and gas industry fluid samples (e.g., source or make-up water, injection water, flowback and produced water, or even product streams), amplification of DNA fragments specific to MIC-causing bacteria, and simple detection of DNA fragments using strip tests that change color. The methods evaluated have performed well in laboratory studies, providing fast and accurate identification of the genetic markers of common MIC-causing bacteria.
Battelle is now ready to expand the range of bacteria groups and move into formal field validation studies of the technology with select industry partners. The JIRP will build upon Battelle’s previous work to validate a field-ready method for bacterial DNA purification, a critical step in transitioning traditional laboratory-based approaches into a robust and efficient solution for field use. The objective is to develop a market-ready field-deployable kit for detection and specification of MIC-causing bacteria types.
Key tasks for the JIRP include:
The study will consist of three phases:
Participating JIP partners will have pre-sale access to the technology and the opportunity to participate in field trials at their work sites. They will also receive the data and results from these trials. In return, partners will share in the costs of the study, which is estimated at $250,000 per partner over a 12-month period. The JIRP is open to operating companies as well as field service companies in the oil & gas industry. There are still a limited number of spaces available.
Can contaminated water from abandoned mines be turned into a viable water supply for hydraulic fracturing operations? The results of a recently completed demonstration project in Pennsylvania suggest that the answer is yes.
Battelle recently completed a demonstration project at Fawn Mine in Sarver, PA. The two-year project, sponsored by the Department of Energy, utilized a novel water treatment technology called Floatation Liquid-Liquid Extraction (FLLX) that removes both metals and sulfates from contaminated water. Now commercialized by Winner Water Services as HydroFlex, the technology uses a dual solvent extraction process to remove contaminants from wastewater. In the demonstration project at Sarver, HydroFlex was shown to reduce sulfate concentrations in Acid Mine Drainage (AMD) by up to 90%—a significant improvement over competing technologies.
With a single gas well requiring up to 5 million gallons of water between initial fracturing and well completion, water use has become a point of contention between oil and gas developers and local communities. At the same time, millions of gallons of water are collecting in abandoned mines throughout the Appalachian area. Left untreated, AMD from these mines can have significant environmental and economic consequences. With HydroFlex, abandoned mine pools can become an economical and convenient source of water for hydraulic fracturing and other operations—a double win for oil and gas companies and the environment.
The technology has been under study since 2008 and was previously validated in bench-scale experiments. The Sarver demonstration project is the first to put the technology to the test in the field for the supply of water to the oil and gas industry. The project used semi-portable, modular treatment units that are capable of processing 100 gallons of water per minute. The resulting water was shown to meet requirements for use in hydraulic fracturing. ArcelorMittal provided access to the Fawn Mine site during the course of the DOE project.
Removing sulfates from mine water has proved to be problematic for companies and agencies engaged in remediation work. Methods for sulfate reduction generally fall into two categories: thermal processes and membranes. Both work by concentrating the dissolved components of the feed water for removal via precipitation or as a concentrated waste stream. Conventional precipitation methods generally are not able to reduce sulfate concentrations much below 1,200 mg/L. Membrane-based processes are more effective, but are very costly, are subject to fouling, and generate a large waste stream.
The FLLX process encompasses two distinct stages – water purification and sulfate recovery. In the water purification stage, sulfates are removed from the wastewater through contact with an organic extractant phase. The sulfate anions associate with the positively charged extractant, which is then separated from the water in a settler. The sulfate is typically reduced by about 70–90%.
The sulfate is then stripped from the extractant phase in a separate extractant recovery stage. A high pH carbonate solution exchanges sulfate anions with carbonate anions, recharging the extractant. A sodium sulfate byproduct solution with potential commercial applications is also generated within this stage.
Winner Water Services will use the results of these studies to make system improvements and optimize HydroFlex for oil and gas and other industrial applications.
The secret to conserving some of the world’s largest creatures could be found in molecules too small to see. Genomic research is shedding new light on bowhead whale populations and migration patterns. These insights are helping the oil and gas community and native Alaska populations work together to make effective decisions that balance conservation, community and development needs.
This past October, Battelle and the North Slope Borough of Alaska sponsored an industry meeting to examine these issues in depth. The conference brought together academics and researchers from across the country with representatives of the oil and gas industry, the North Slope Borough, the International Whaling Commission (IWC), and indigenous communities. The two-day symposium, held at Battelle’s headquarters in Columbus, OH, provided participants with opportunities to network and catch up on the latest developments in the field.
Battelle scientists shared updates from their genomic research at the symposium. Additional sessions covered the biology of bowhead whales, an introduction to genomic research methods, and presentations on metagenomics, population genomics and mitochondrial genetics. Each day featured a special lunch presentation. On day one, Harry Brower Jr. of the North Slope Borough discussed the bowhead whale’s role and importance in native Eskimo culture. On day two, author Hans Thewissen shared research on whale evolution and fossil documentation from his latest book, The Walking Whales. The symposium wrapped up with a panel discussion summarizing lessons learned and next steps for the research community, IWC and North Slope Borough.
Bowhead whales are important to native Alaskan Eskimo communities for both subsistence and ceremonial purposes. They are also protected by national and international conservation laws. Oil nd gas developers operating in the Beaufort and Chukchi Seas must understand bowhead whale populations and migration patterns so that their activities do not negatively impact either whale populations or the Eskimo hunts, both of which are protected by the Marine Mammal Protection Act.
Genomic research conducted by Battelle on behalf of IWC, the North Slope Borough and the Alaska Eskimo Whaling Commission has helped scientists answer important questions about the size and diversity of the bowhead whale population. Genomics also provides insights into whale evolution, population dynamics, movement patterns and the spread of diseases in populations. The research helps scientists better understand the vulnerabilities of specific bowhead populations and of the species as a whole.
The IWC uses this research to set hunting quotas for Eskimo communities. It is also used to help the oil and gas community understand the risks of different activities and make better decisions to balance conservation and development priorities. The symposium brought stakeholders together to further define the role of genomics in environmental monitoring and conservation.
Battelle is continuing work with the IWC and North Slope Borough to understand and monitor bowhead whale populations over time. Similar work is now underway with gray whales in the Northern Pacific.
How do you prioritize mitigation efforts for pipeline integrity? Researchers at Battelle are applying sophisticated modeling methods to help companies quantify risks to oil and gas pipelines and develop risk profiles for critical infrastructure.
There are 2.6 million miles of liquid petroleum and gas transmission pipelines in the United States alone, delivering trillions of cubic feet of natural gas and hundreds of billions of ton/miles of liquid petroleum products each year. While the vast majority of pipelines will operate safely for many years, there are a number of risks that can threaten pipeline integrity, potentially leading to accidental releases, fires and explosions. Corrosion, construction accidents, material defects and operator errors can cause dangerous incidents that put both people and property at risk.
According to the Pipeline and Hazardous Materials Safety Administration (PHMSA), there were 6,335 reported pipeline incidents between 2005 and 2014, resulting in more than $5 billion in total damages and 152 fatalities. An average of 15 people are killed and 62 are injured in pipeline accidents in the U.S. each year.
In order to protect workers and the public and minimize the costs of pipeline incidents, companies need to have a clear understanding of the unique risk profile for each section of their operations. As infrastructure ages and growing communities encroach on transmission pipelines, it’s more important than ever for operators to understand the risks so that they can make effective asset management decisions.
Battelle provides safety and risk assessment services for oil and gas companies and pipeline operators. The research team brings together deep expertise in materials science and engineering with cutting-edge statistical and computer modeling methods.
There are several steps to the risk analysis process:
Battelle has a long history of pipeline integrity work for the oil and gas industry, including work on corrosion detection and mitigation, development and evaluation of pipeline inspection technologies, and underwater robots for pipeline inspection and repair. The breadth of experience offered within Battelle allows researchers to leverage scientific advances made in other fields—such as national security, pharmaceuticals or materials science—for the benefit of the oil and gas industry. Their pipeline integrity work builds on more than twenty years of experience in risk modeling and assessment for the U.S. military and other industries.