New Industrial Automation Strategies for Shale Gas Operators

New Industrial Automation Strategies for Shale Gas Operators

This post was written by Randy Miller of Honeywell Process Solutions.

 

Global trends in the demand and supply of energy require constant improvement of technologies and services, exploration, and production. In this environment, shale gas has emerged as a key unconventional resource. With current operating challenges, the shale gas industry requires access to real-time data and improved process control capabilities to continually optimize the performance of wells with rapidly changing production profiles, particularly as reduced drilling activity increases production variability across assets. This post describes a holistic, integrated approach to address operational efficiencies and manage capital expenditures for shale gas producers, encompassing gas production, processing, and automation. This approach drives greater agility, enabling operators to adapt to business conditions quickly and cost effectively, to help ensure profitability in uncertain times.

Growing importance of shale

Increased production of natural gas in North America in recent years has been attributed, in large part, to the development of shale gas resources. This type of unconventional natural gas is trapped in a free or adsorbed state in shale or mudstone formations, which are mainly composed of methane. The production of natural gas from shale formations is one of the fastest-growing segments of the global oil and gas sector. In addition to North America, shale gas sources have been identified in China, Argentina, South Africa, Australia, and throughout Europe. According to the U.S. Energy Information Administration’s Annual Energy Outlook 2012, shale gas production will increase from 5.0 trillion cubic feet per year (23 percent of total U.S. dry gas production) in 2010 to 13.6 trillion cubic feet per year (49 percent of the total) in 2035.

Shale gas production is very process intensive, with many applications in extraction, separation, treatment, environmental monitoring, and distribution requiring effective process control technologies. Exploration and production (E&P) companies are investing considerable resources in not only developing well pads, but also in equipping each producing pad and building with gathering systems and installing centralized facilities to accommodate production streams, which are often multiphase with varying combinations of gas and liquids. The complexity of liquids-rich shale assets can be problematic throughout all stages of field development, including well planning and construction, facilities deployment, and operations. Furthermore, accelerated production decline and a tightening regulatory environment leave little margin for error.

New, permanent demand for shale gas is emerging in residential heating (from heating oil), ethylene and basic chemicals manufacturing, and liquefied natural gas international exports. These new opportunities are changing the landscape of gas from regional to global, adding new complexities to the value chain.

Increased operational demands

Owner-operators and independent E&P companies require effective strategies to deal with this increasing complexity, including difficult operational, environmental, and regulatory demands, as they strive to refine hydrocarbon products safely, efficiently, and profitably. The recent phenomenon of falling oil prices only complicates this situation.

The key challenges facing shale gas producers relate to the safety, reliability, efficiency, and flexibility of their operations. For instance, there is a crucial need to improve safety by reducing and mitigating incidents. Operators must also comply with critical infrastructure protection regulations while reducing human error, improving emergency response, and minimizing liability. From a reliability standpoint, they need to improve asset availability, and at the same time, protect high capital cost equipment, enhance production facilities and field life, and extend overall investments. The demand for greater efficiency includes reductions in operating costs and energy consumption, along with increased production rates. Operators also require increased agility to exploit regional dynamics and opportunities, as well as anticipate and manage changes in composition and volumes. Finally, they must adapt to changing regulatory requirements and reduce risk in volatile operating environments.

Key challenges facing shale gas producers relate to the safety, reliability, efficiency, and flexibility of their operations.

To boost profits, shale gas producers want to maximize ultimate product recovery while lowering capital expenditures and operating expenses—no easy task, as it often entails increasing energy efficiency, reducing reactive maintenance, extending asset life, and eliminating unplanned downtime. This effort encompasses everything from process optimization to operator training and effectiveness.

There is also an urgent need for reliable remote operations capabilities in almost all areas of the oil and gas field. Distributed assets can include multiple pods of local control, which must be unified and operated as a cohesive asset. Traditionally, these local pods of control were managed by legacy automation with stand-alone local databases—all with their own life-cycle management, maintenance requirements, and high failure rates.

Shortages of qualified staff, brought about by the departure of retirement-age workers, affect shale operators’ ability to capitalize on emerging technologies. Without appropriately skilled personnel, producers cannot always meet the demand that exists.

Although some operating companies are taking advantage of leading-edge control and automation technologies, much of the industry still uses fairly rudimentary controls—focused primarily on safety and uptime—with little in the way of yield and throughput optimization.

Many companies have grown weary of the time and effort required to manage applications—many of which are homegrown. They want to work with a vendor that has the expertise to manage the life cycle of infrastructure and applications, freeing the operators to focus their attention on production.

Engineering, procurement, and construction firms serving the shale industry cope with a different set of challenges: Multiple supplier bid packages must be integrated into a single, seamless system to manage operations. This scenario presents problems associated with product maturity, obsolescence, mismatched communication protocols, incompatible operating systems, etc. Managing disparate assets over their entire lifetime can be bothersome, to say the least.

With the rapid pace of shale play development in recent years, companies often delayed automation investments. Operators devoted their resources to bringing new oil and gas reserves to customers. Automation upgrades fell behind the curve, and control system projects were held off the critical path—even if they could contribute to improved production capabilities and human capital efficiency.

Today, shale operators are striving for an entirely new approach to automation to deal with low prices, fast production drop-off, constrained capital expenditures (CAPEX), and a proliferation of isolated wells. With fewer formalized automation departments, nagging capacity issues, and a squeeze on capital projects, they are searching for an operating expense-driven approach that allows flexibility in future technology adoption.

Incorporating process and operating knowledge into advanced control and automation solutions helps shale producers achieve operational excellence.

Holistic approach to technology

Now, more than ever, shale gas producers need to partner with solution providers to ensure they can monetize their resources in a timely, capital-efficient manner. Success often hinges on executing gas projects quickly at reduced cost compared to traditional methods, as well as making sure projects can maximize the recovery of high-value products at low production cost and downtime.

From an operational perspective, reservoir operators want to use their assets more effectively and manage production better. Due to the current slowdown in well completion, they have more time to consider the return on capital that automation can deliver.

Major suppliers to the oil and gas industry have taken steps to incorporate process and operating knowledge into advanced control and automation solutions to help shale producers achieve operational excellence. Integrated automation with gas processing equipment can significantly reduce the impact of bottlenecks in the gas value chain by compressing schedules up to 30 percent and reducing commissioning time with versatile, integrated modular solutions. Flexible universal automation also allows companies to make changes programmatically, rather than by the traditional rework to physical cabinets and field wiring, leading to faster startups.

An integrated approach to automation enables operators to remotely monitor the entire shale gas production process from collection to distribution through distributed control and centralized management. At the same time, it helps them keep track of equipment operation to guarantee safe and reliable production. Users can closely analyze processes and make improvements that will maximize on-stream performance and business results. Remote operations monitoring tools validate and transform raw data into actionable information. Operators can react quickly to ever-changing conditions across production assets using standardized calculations for maximum efficiency.

The latest technology advancements for shale gas production range from modern distributed control systems (DCSs)—which enable E&P firms to more tightly control their processes and produce oil and gas in greater volumes than ever before—to advanced process control and optimization applications that increase throughput and yields of unconventional gas facilities, to unified solutions for fire and gas, incorporating gas detectors, fire detectors, fire alarm panels, safety integrity level 3-certified programmable logic controllers, and an integrated fire and gas safety system. In addition, the current breed of smart field devices supports instrument asset management strategies via industry-standard protocols such as HART, Profibus, and FOUNDATION Fieldbus.

Technology innovations, such as a new generation of RTUs, enable greater connectivity and data integration across the enterprise.

Technology innovations also enable greater connectivity and data integration across the enterprise. For example, a new generation of remote terminal units (RTUs), featuring native redundancy, expanded I/O modules, and wireless I/O, have more communication flexibility and provide visibility into efficient utilization of distributed assets through expanded remote monitoring, diagnostics, and asset management. They are designed for companies to deploy at remote sites with very low power consumption and may use solar power. As a result, operators can perform remote maintenance and dramatically cut equipment monitoring and diagnostic time.

Combining the new RTUs with an enhanced supervisory control and data acquisition (SCADA) platform further helps operators realize the production potential of their distributed assets. This approach simplifies configuration over thousands of assets and improves operational efficiency with a better human-machine interface. It serves as an integration backbone across the gas value chain, allowing multiple SCADA servers to operate as one within a single asset or across the enterprise. Applications that are native to the SCADA platform complete the operations integration, including the management of safety, asset integrity, and product movement both upstream and downstream.

Leading automation suppliers have responded to the need for project optimization with innovative, enabling technologies like virtualization, universal I/O, and cloud engineering. These solutions help operators do away with traditional task dependencies and sequential work processes, drastically improving the overall project schedule and keeping control systems off the critical path. Revised project methodologies rely on separating physical from functional design, using standardized designs, and enabling engineering to be done from anywhere in the world.

To support integration across their value chain, shale gas operations can leverage methodologies unifying state-of-the-art process and automation technologies. Innovative gas treatment, purification, and processing techniques help optimize the development of unconventional, remote, and subquality gas resources, which are vital contributions to the world’s gas supply. Using the latest sophisticated techniques, operators can remove impurities from gas so it can be transported by pipeline, as well as recover valuable condensate and natural gas liquids, such as ethane, propane, and butane.

Shale developments typically come online incrementally and have strict capital efficiency requirements. As such, they benefit from pre-engineered, factory-built modular plants that provide flexibility for changing feed and product requirements. With modular plants, companies can deliver and install liquid gas recovery units faster than with stick-built alternatives. Plant fabrication can occur in tandem with drilling, fracturing, and well testing. For operators developing new resources, these new capabilities to parallel the field and plant development processes are essential to bringing on new assets quickly. They also provide a rapid return on the large capital outlays required to meet growing shale development.

Implementing modular plant techniques, coupled with pre-existing and standardized automation designs, operator displays, etc., helps “de-risk” projects and reduce the time to commercial startup. Site acceptance tests can be performed more smoothly on proven standard units, and users realize the value of embedded process expertise in their plant automation system in the form of procedural operations, advanced control strategies, and operator training and simulation.

By employing modular design and construction, equipment can be easily shipped to remote locations where gas is often discovered. This allows operators to begin processing gas and earning revenue more quickly. Common parts, which simplify maintenance and training, also bring greater ease of operations.

Benefits to gas producers

With the uncertainty of global energy demand, shale gas producers must take an objective look at their production operations to make efficiency improvements and eliminate unplanned production downtime. Those firms applying a successful automation strategy that allows them to enhance the safety, reliability, efficiency, and flexibility of their operations will be in an even stronger position when demand recovers.

With tight integration of all key aspects of production, processing, and transportation, operators can compete more effectively under the toughest economic conditions. This approach addresses fragmentation across the gas value chain, closes gaps created by interfaces between different operating companies, brings together a wide range of “best-of-breed” point solutions, and unifies control schemes with the DCS to enable operational excellence at startup and beyond.

The typical results of a holistic strategy for gas industry projects include:

  • compressed schedule and faster startups
  • reduction of automation change orders
  • increased process efficiency
  • improved operational reliability
  • enhanced asset integrity
  • stabilization of production
  • enablement of smoother startup
  • elimination of operator errors
  • reduced cost and risk
  • improved plant safety
  • maintaining physical security and cybersecurity
  • protecting equipment, the environment, and workers
  • optimized knowledge transfer
  • improved product quality

With real-time automation and communications, companies can monitor, control, and enhance production operations through smarter networks that can be accessed anytime and anywhere using smartphones, tablets, and personal computers. Indeed, wireless communications give operators the reliable, real-time information needed for optimizing production.

The increasing use of modular equipment reduces field construction time and lowers capital and operating costs for shale gas operators, and allows them to achieve aggressive schedules to first gas, which can generate significant incremental value. Modular, prefabricated solutions enable economic development of shale gas resources that would otherwise be daunting processing challenges given their inherent variability in gas composition.

Shale developments benefit from pre-engineered, factory-built modular plants that accommodate changing feed and product requirements.

Ultimately, an integrated approach to gas industry projects overcomes the inherent drawbacks of consolidating a host of third-party vendors and technologies. Instead, it establishes a foundation for building new infrastructure, streamlining capital and equipment costs, and shortening the cycle for reaching profitable operation.

Seeking efficiency

The oil and gas industry, and in particular the development of shale gas exploration and extraction, stand to realize important advantages from the unification of process and automation expertise by major suppliers. This approach is key to expediting production, improving operating agility, and ensuring peak performance throughout the project life cycle.

The best way forward for operators is integrating the various assets for plant automation, gas processing, and transportation with process technology know-how applied early to systems that positively impact long-term financial and operating performance. Between reduced time to startup and lower life-cycle costs, the benefits are substantial throughout the gas value chain.

About the Author
Randy Miller has been with Honeywell Process Solutions in Thousand Oaks, Calif., since 1988, taking on many different roles in applied research, product development, product management, sales, business development, and sales management. In his current role as global marketing director, he leads portfolio strategy and business growth in the oil and gas value chain. Miller has a BS and MS in chemical engineering from the University of Alberta.

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A version of this article also was published at InTech magazine

What Are the Benefits of Oxygen-Based Fuel Controllers for Biomass Plants

What Are the Benefits of Oxygen-Based Fuel Controllers for Biomass Plants

This article was written by Andrew Gentile, PE, lead facilities engineer at Andeavor Logistics and Sheldon Schultz, PE, is the general manager of Yanke Energy, Inc.

Fuel delivery is a common problem in biomass plants. Wood fuel is not uniform in shape, density, moisture content, ash content, or energy content. In plants operating in manual mode, an operator makes a fuel adjustment every 5 minutes. More often than not, the adjustment is excessive, causing predictable system oscillations, which cause decreased efficiency, boiler upsets, lower steam production, and emissions violations. The fact that wood fuel is problematic is the justification many plants use for resorting to manual fuel control.

 

For plants that use automated fuel control, a pressure-based controller is the most common. A pressure-based controller depends on variations in drum pressure to make fuel adjustments. Percent oxygen (O2) is a leading indicator of drum pressure; therefore, a pressure-based controller is slower and less accurate than an O2-based controller. An O2 controller can predict pressure errors and adjust the fuel rate before the error occurs. An O2-based fuel controller stabilizes the combustion process, which increases steam flow, reduces average percent O2 (leading to greater fuel efficiency), and reduces the chances of emissions violations. A well-designed controller will pay for itself within a year.

The controller concept

Figure 1 shows a characteristic curve for a theoretical boiler. The curve represents the interrelationships between swings in O2, load efficiency, and the production of carbon monoxide (CO) and nitrous oxide (NOx). The corner point is the ideal percent O2 operating point for a given boiler. Each boiler has a unique ideal operating point. The role of the O2 controller is to stabilize the combustion process around the boiler’s ideal operating point. Given a fixed amount of air flow into the furnace, the controller varies the fuel rate to maintain a percent O2 set point. The operator selects the amount of air flow based on the desired steam flow or megawatt (MW) output. Because the air is constant, the percent O2 in the flue gas only increases if the amount of air being consumed in the combustion process decreases. Increasing percent O2 is a leading indication of decreasing drum pressure and steam production. A decrease in percent O2 in the flue gas occurs if the amount of air being consumed has increased; decreasing percent O2 is a leading indication of increasing drum pressure and steam production.

Figure 1. Characteristic curve of boiler

Case study

An O2 controller was installed in boiler #1 in 2010. Process data was collected in 1 minute increments on 8 June 2010. Steam flow, drum pressure percent O2, feed rate, and control mode (auto or manual) were collected. The data elements are represented as a percentage of their respective averages. This was done to compare the data on relative terms. Actual values are in table 1.

Manual control results

Figure 2 shows 100 minutes of percent O2 and feed screw speeds while operating in manual mode. The changes in percent O2 vary inversely as the metering screw speeds. Percent O2 lags the changes in fuel rate by about 1 minute. The range of percent O2 in figure 2 is 2.73 percent to 7.94 percent.

The three severe dips in percent O2 at the beginning of figure 2 can be directly correlated to increased CO levels. CO is used as a surrogate volatile organic compound by maximum achievable control technology as an indication that other hazardous air pollutants are present. The three peaks in percent O2 in the middle of the graph can be correlated to lost revenue from decreased steam production.

Figure 2. Percent O2 swings based on fuel variations, manual

The metering screws are controlled by variable frequency drives (VFDs); screw speeds are entered by the operator in hertz. In 100 minutes, the operator makes 24 changes ranging in magnitude from –15 Hz to 10 Hz, with the average adjustment magnitude of 5.08 Hz. The average VFD speed is 36.05 Hz.

Figure 3 shows variations in steam flow and drum pressure with feed screw speeds. Steam flow and pressure respond similarly to changes in fuel rate, both lagging the fuel changes by about 5 to 6 minutes, which mean they lag changes in percent O2 by about 4 to 5 minutes.

Figure 3. Pressure and steam swings based on fuel variations, manual

Automated control results

Figure 4 shows 100 minutes of percent O2 and feed screw speeds while operating in auto mode. The controller set point was 4.97 percent. The range of percent O2 shown is 3.84 percent to 6.09 percent. The average percent O2 was 4.97 percent. Note that the magnitude of changes is much smaller than it was in manual mode. In 100 minutes, the controller makes 80 changes ranging in magnitude from –3.5 Hz to 2 Hz, with the average adjustment magnitude of 1.18 Hz. The average VFD speed is 33.24 Hz. (It is likely that the controller made more than 1,000 speed adjustments in 100 minutes. The data collection was set up for 1 minute intervals, and so higher frequency changes are not represented.)

Figure 4. Percent O2 swings based on fuel variations, auto

Figure 5 shows variations in pressure, steam, and feed screw speeds while in auto mode. The steam flow is higher and more consistent than in manual mode. The average steam flow shown in figure 5 is 67,129 lbs per hour with a standard deviation of 698.9 lbs. per hour. This represents approximately 1 percent variance from average.

Note the differences in pressure and steam waveforms between figures 3 and 5. In manual mode, the pressure and steam waveforms are nearly sinusoidal. In figure 5, there are still some oscillations, but the frequency is much lower and the magnitude smaller.

Figure 5. Steam swings based on fuel variations, auto

Comparison of data

The average steam production for the manual control data was 58,595 lbs. per hour; the average steam production for the auto control data was 67,129 lbs. per hour. This is an increase of 14.6 percent, or approximately 1 MW in electrical output. (Note that the case study assumes that the same fuel was used throughout the course of the day. No information is known about possible changes in fuel quality, which may have contributed to the improvement in steam production.) At 6¢ per kWh, this represents a potential increase in revenue of $480,000 per year. Furthermore, it can be inferred from figures 2 and 3 that in manual mode the CO emissions were significant, and in the auto mode the emissions were negligible.

To maximize steam flow and to minimize emissions problems, the combustion process must be stable. An O2 controller is designed specifically to stabilize combustion. Although a pressure-controlled system may be better than a manual system, a pressure-controlled system is designed to correct an error in drum pressure that has already happened. An O2 controller can predict and prevent the error from happening.

In the case study of boiler #1, the O2 controller helped the plant to produce more steam. It enabled the plant to run with a lower average percent O2, lowering operating costs, and the increased stability of the combustion process helped to minimize emissions violations.

About the Authors

Andrew Gentile, PE, is lead facilities engineer at Andeavor Logistics. Previously, he was president of Gentile Engineering, Inc. where he does design work in electrical power distribution and control systems. He is currently working in the petroleum industry developing control standards for distributed networks in pipeline applications.

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Sheldon Schultz, PE, is the general manager of Yanke Energy, Inc. Schultz has designed, built, and operated numerous renewable energy generation facilities. He is currently doing consulting work for biomass facilities. He specializes in improving boiler performance and emissions control.

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A version of this article originally was published at InTech magazine

Webinar Recording: The Growing Cybersecurity Threat to Natural Gas Distribution Systems

Webinar Recording: The Growing Cybersecurity Threat to Natural Gas Distribution Systems

This guest blog post was written by Pierre Dufour, a global product marketing manager at Honeywell Process Solutions. This post was written in conjunction with a co-hosted webinar on cybersecurity threats to natural gas providers. Click this link to watch the webinar replay

 

As I observe today’s natural gas market, I see companies under pressure from many forces in the world. Among these is the multiplicity of computer and communications systems that must be protected from those who would do harm to gas transmission and distribution capabilities.

Natural gas is the foundation fuel for a clean and secure future, providing benefits for the economy, environment and energy security. Alongside the economic and environmental opportunities of natural gas, there comes great responsibility to guard vital distribution assets from cyber attack.

In a connected world, with increasingly sophisticated electronic threats, it is unrealistic to assume gas delivery systems are isolated or immune from various forms of electronic compromise.

Relevant operational and business data are available in many places on the gas grid, most of the time. Companies want to be as easy as possible to take this information and make it useful. This includes solutions that regularly pull and store relevant gas meter data in a secure cloud. Gas metering data must also be collected more frequently and in smaller increments.

Leading automation suppliers provide advanced gas measurement and data management solutions to the natural gas industry. These solutions provide seamless connectivity and round-the-clock access to critical data and diagnostics. Companies also employ the capabilities of the Industrial Internet of Things (IIoT) to do automated meter reading. But, they need to do more than just collect reams of data for billing and back office analysis. Gas operators must be able to make decisions and take action at every level of their distribution system, optimizing analytics where it makes sense and enabling multiple applications to run edge devices to solve problems in new ways.

Learn how to improve the overall security of your metering installed base and reduce the chances of vulnerabilities being exploited. Watch the co-hosted webinar recording presented by Pierre Dufour of Honeywell and Steve Mustard, ISA leader and industrial security expert. Click this link to watch the webinar replay.

In any IIoT-based communication system, it is essential to ensure that sensitive information reaches its intended recipient, and that it cannot be intercepted or understood by a malicious individual or device. A cyber attack on devices that control the gas grid could result in disruption of operations or damaged equipment. Any device or system controlled by network communication that “faces” the Internet is at risk of being hacked.

Natural gas firms require a fully integrated, end-to-end technology platform for gas transmission and distribution. This platform should be based on a single design standard and follow strict cybersecurity and information technology data security guidelines uniformly across all components. As such, there will be no weak link to be exploited by cyber criminals.

It is crucial to implement cybersecurity solutions that are specifically intended to protect sensitive gas consumption information at both the data storage and data transfer levels. For example, there are security advantages to deploying an architectural design that ensures integrated, low-power cellular modems operate on the network for the shortest possible time – perhaps only a few minutes per day. This greatly reduces cyber vulnerabilities compared to approaches where modems remain on continuously.

In conclusion, natural gas providers are seeking to run a better business by implementing smarter, more responsible solutions for the customers they serve. Key to this effort is protecting all critical gas metering and data management assets from cyber threats. There is no substitute for sound, well-engineered cybersecurity processes, which reduce risks, mitigate hazards, and keep sensitive operational and business data safe and secure.

border_color=”#DDDDDD” rounded_corners=”false” inside_shadow=”false” outside_shadow=”false”] About the Author
Pierre Dufour is a global product marketing manager at Honeywell Process Solutions. He has been with Honeywell for over 20 years. He holds an engineering degree in electronics and an MBA. Pierre has worked in multiple departments including Technology, Product Specialization and Marketing. He is based out of the Honeywell Mercury Instruments site in Cincinnati, Ohio.

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How to Measure pH of Ultrapure Water in Power Industry Applications

How to Measure pH of Ultrapure Water in Power Industry Applications

This article is from the January/February 2015 issue of InTech magazine and was written by Fred Kohlmann, Midwest business manager for analytical products with Endress+Hauser

Water covers more than 70 percent of the earth’s surface and has varying degrees of purity in its natural form, ranging from crystal clear pure mountain spring water to highly saturated brine sea water. In the power generation industry, ultrapure water is used as a source to make steam to drive turbines and for other uses. Ultrapure water does not cause corrosion or lead to stress cracking in equipment such as turbine blades, stainless-steel lines, steam circuits, and cooling systems. Power companies use a great deal of ultrapure water, upward of 500,000 gallons per day for large plants. The ultrapure water can be processed from city water, a nearby river, or even seawater.

measuring-pH-ultrapure-water-power-industry

In most cases, the systems for producing ultrapure water are supplied by specialists in electrodionization, membrane, reverse osmosis, and other techniques for purifying water, and all require pH monitoring. Not only is pH monitoring required when the water is purified, it is also required as the water is used to maintain correct pH.

The bottom line in power plants is that improperly conditioned water—based on a number of parameters, of which the main two are conductivity and pH—leads to corrosion and scale, which leads to inefficient operation and damage to vital parts.

In the boiler, deposits cause heat transfer problems, reducing steam production capability. Corrosion from these deposits weakens the metal, leading to tube leaks that negatively impact the production of steam. Large boilers, condensers, economizers, and superheater tube leaks can cause adjacent tubes to fail and are actually the largest cause of forced boiler shutdowns.

The steam that passes through the turbine can cause deposits and corrosion from minerals, organics, and detergents that are present in plant water sources. Deposits on the turbines can cause pressure drops and unbalance the turbine, reducing speed and generation capacity.

Unfortunately, conductivity measurement by itself does not provide enough water quality information for ultrapure water chemistry; therefore, pH must also be incorporated. Unless controlled, the effects of improper water treatment parameters will cause boiler tube failures and loss of efficiency due to coating of the tubes. This makes energy costs and ultimately operational costs higher. Boiler manufacturers have tight specifications on the minimum and maximum water quality parameters, pH being one of them.

Water’s tough

Water in its pure state is one of the most aggressive solvents. Known as the “universal solvent,” water, to one degree or another, will dissolve virtually everything to which it is exposed. Because pure water has a deficiency of ions, it looks for equilibrium with the ions it comes in contact with, and so it wants to strip these ions away from its host.

For the purposes of this article, pure water is defined as having a conductivity between 0.055 to 10 microSiemens per centimeter (µS/cm), or 18.2 to 0.1 megohms-cm. Common manufacturer specifications for pH sensors can indicate a conductivity range of 10 µS/cm or greater.

Herein lies the first hurdle to best measurement practices: to find pH sensors that are specifically designed to measure water with conductivity less than 10 µS/cm. Fortunately, some pH sensors are able to measure down to 0.1 µS/cm, but these are specialized instruments and must be specified, installed, and maintained accordingly.

 

There is a deficiency of ions in pure water, and pH sensors have the reputation of being noisy when measuring pH in these low ionic strength solutions. In simple terms, the signal is noisy because the sensor is looking for ions to capture and measure and has a hard time finding them, causing the measured value to meander up and down the pH scale.

Using two or more brand new pH sensors from the same manufacturer—even right after being freshly calibrated in 7 and 4 pH buffers—the sensors may show differing values due to static charges and reference junction potential errors. Pure water is a poor conductor of electricity, and so static charges are an issue as water flows through the piping systems, requiring extra care in proper grounding for signal stability and noise rejection.

Also, extraneous electromagnetic interference (EMI) and radio frequency interference (RFI) can disturb the sensor’s electrical circuitry, especially in a power plant with high-voltage equipment. Walkie-talkie transmissions and electric motors or valves being cycled on and off can also create electrical noise. These interferences cause signal spikes that push the pH signal high or low for brief moments or freeze the signal in place.

The pH sensors use a two-electrode scheme as the measurement apparatus—an active or measuring electrode and a reference electrode. The active electrode can have an input impedance of 100 megohms in high ionic strength solutions such as a pH 7 buffer. So in the best of circumstances, pH measurement has at least a 100 megohm obstacle to overcome. If that same impedance is added to the very low ionic strength of ultrapure water, it adds measurement complexity. There is now a larger resistance for the signal to traverse through the low ionic solution.

The reference junction serves as the return or ground path for the pH measurement. Any shifting of the electrical resistance in the reference path will change the overall resistance of the measurement and cause a shift in pH reading. This equates to a noisy signal. A charge buildup at the reference junction can change as the process changes (e.g., when valves or pumps are cycled) or remain at a constant state and attenuate the pH signal.

If any air is introduced into the piping system of the pH sensor, it will add CO2 into the solution, which acidifies the actual pH value. Therefore, closed loop systems are needed for a constant and uniform measurement.

Consider the practice of taking a grab sample from a closed loop system for pH analysis. When one walks the sample back to the chemistry lab for analysis, what happens to the sample as it is exposed to the atmosphere? It likely changes, sometimes substantially, leading to a preference for in situ sensors.

Changes in the flow rate past a sensor can also lead to changes in the pH measurement. These changes are referred to as streaming current potentials. Changes in process flows cause changes in the reference junction potential and lessen the ability of the glass electrode to maintain its hydrated outer gel layer.

Problems can occur in pH sensor cable connections, terminal strips, and plugs. Connectors can become loose or corroded or have moisture accumulate across the connections. These situations change the resistance of the pH measurement and degrade the signal.

Long runs of cables without the aid of preamplification or signal conversion from analog to digital can lead to changes in the capacitance and resistance of the cable, which can affect the pH readings. Signal cables are also a means by which EMI and RFI can gain access to the transmitter circuitry, also causing measurement errors. Here are best practices for installing and maintaining pH sensors:

  • Make the pH measurement in a sealed piping system
  • Maintain a slow continuous flow rate past the pH sensor, about 100 mL/min
  • Use conductive piping and fittings; 316 SS is common practice
  • Keep cable runs as short as possible
  • Maintain tight, dry, and corrosion-free electrical sensor connections
  • Store unused pH sensors in a solution to maintain hydration: 4 or 7 pH buffer
  • Use digital pH sensors instead of analog

Inside pH sensors

Many manufacturers offer pH sensors designed specifically for measuring pH in low ionic fluids of 10 µS/cm or less. Low-resistance glass and double and triple reference junctions, as well as flowing reference junctions, are employed with high degrees of success. Ceramic junction materials tend to have less “memory” and facilitate fast response times.

The pH sensors using a flowing junction reference system (figure 1) tend to be more accurate as they minimize junction potentials, but they also require more maintenance. These types of systems use a reservoir of potassium chloride (KCl) solution pumped through the sensor’s reference element, and use either gravity or compressed air to maintain a constant overpressure as compared to the process being measured.

Figure 1. Flowing reference pH sensor with reservoir

Figure 1. Flowing reference pH sensor with reservoir

Process fluid will eventually find its way through the junction and into the filling solution of the reference electrode. When this happens, it dilutes the KCl inhabiting this physical space. This dilution of the KCl will eventually lead to a change in the reference chemistry and to measurement inaccuracies.

Flowing reference-style sensors deliver a fresh KCl solution through the junction and provide a constant nonchanging electrical reference path. These sensors also deliver a pH reading much faster than traditional sealed reference electrodes.

Sealed reference-type pH sensors employ salt rings or circular pinhead-type reference junctions. Salt ring–type junctions may employ gelled KCl solutions to maximize the junction surface area and keep KCl flow at an optimum rate. Some of these sensor styles may also use an internally charged or pressurized reference. Because these sensor types are considered closed systems, they have no reservoir to maintain, and the entire sensor is replaced as its reference becomes contaminated or as the solution within the reference gets depleted or becomes unusable.

Temperature compensation of the pH signal is very important to accurately measure the pH of ultrapure water (figure 2). An entire paper discussing this subject could be written, but is not within the scope of this article. As temperature changes, so does the pH sensor’s millivolt output. Specifically, the electrode produces more millivolts/pH as the temperature increases, and as the pH goes farther in either direction from 7 pH. This change is predictable and linear, and can be compensated for in the pH analyzer by using the Nernst equation in the circuit design.

Figure 2. Temperature as it relates to pH

Figure 2. Temperature as it relates to pH

The Nernst equation (figure 3) is a general mathematical equation that describes and predicts the pH electrode’s output based on a number of constant factors and just one variable, temperature.

Figure 3. Nernst equation showing breakout of potentials and slope

Figure 3. Nernst equation showing breakout of potentials and slope

Modern pH measurement systems incorporating temperature-compensated pH sensors are the norm. Avoid any pH sensor that comes without an integral temperature element or a transmitter that only accepts a manual or fixed temperature compensation network. A fast acting/responding temperature element should be mounted in the bulb of the pH sensor for best results.

Electrical considerations

Cables for pH sensors must be kept as short as possible, less than 10 feet without some type of preamplification or signal conversion. Furthermore, sensors should employ gold connections and O-ring sealed connectors, or use a digital inductively coupled sensor-to-cable connection to avoid EMI/RFI intrusions and moisture and corrosion problems.

There are sensors (figure 4) that convert the pH signal from an analog to a digital value at the sensor and send this digital signal up to 300 feet from the sensor to the transmitter. These digital pH sensors are available from several vendors. Most are not affected by moisture or contamination of connectors.

Figure 4. pH sensors convert the pH signal from an analog to a digital value at the sensor, and send this digital signal up to 300 feet from the sensor to the transmitter.

Figure 4. pH sensors convert the pH signal from an analog to a digital value at the sensor, and send this digital signal up to 300 feet from the sensor to the transmitter.

When using analog-type pH sensors, a common problem is a ground loop. A ground loop is a difference in the ground potential that the pH sensor sees versus the ground potential of the pH transmitter. Ground loops can be a constant or varying offset of voltage to the pH reading (leading to an inaccurate pH value). They can also be an on/off type signal that falsely increases or decreases the pH signal to the transmitter when an electrical device using the same ground is either turned on or off. Ground loops can be hard to find and tougher still to eliminate, but using inductively coupled digital pH sensors eliminates ground loop problems.

Calibration

Calibrations of pH sensors should be conducted regularly. This can be done during a process shutdown or by simply replacing the sensor with a calibrated unit.

The use of the proper buffer solutions is a must, as calibrations need to be made in pH 7 and 4 buffers, never pH 10. Also, properly rinsing and drying the sensor between buffer immersions is critical for accuracy. It is also important to ensure the glassware and other equipment interfacing with the buffer and sensor are clean and free of contamination. Calibrations should be made in accordance with the manufacturer’s recommendations, and proper care should be taken when cleaning the pH sensor.

If large step changes in buffer readings occur from the previous calibration, the sensor is suspect and has either been damaged or contaminated. It should be cleaned properly to get the calibration closer to the last values. Large shifts in calibration values are not normal in ultrapure water chemistries.

Digital pH sensors allow calibration in the laboratory or shop with either a separate transmitter, an alternate channel on a multichannel instrument, or hardware/software that allows hardware to directly connect to a PC. With digital pH sensors, spare precalibrated sensors can rotate in and out of the process as needed.

Calibration in this manner allows for longer and more accurate aging of the sensors in the calibration buffers. Also, a technician is not under pressure to have calibrations done on site while the system is down awaiting calibration completion and reinstallation of the sensor. This scenario is not possible with analog-type pH sensors, which is another advantage of digital pH sensors.

Calibrated pH sensors not in use should be stored in a 7 pH buffer or 3 molar KCl solution. A pH sensor should not be allowed to go dry, either in the process or during storage. If left to become dehydrated, the glass electrode will show higher electrical impedance from the norm and will react much more slowly to pH changes. It may take from a few minutes to hours or even days for the sensor to regain its original operational performance, if ever.

Repeated cycles of hydration and dehydration significantly shorten the pH sensor’s useful life. The reference electrode is also affected by dehydration. If left dry, salt from the internal KCl fill solution will form salt crystals and cake the outer surface of the junction. Ultimately the junction may siphon out all its fill solution.

Companies should premount and plumb pH sensors in stainless-steel flow loops (figure 5), where they are easily accessible for service and maintenance and where flow rates can be easily controlled.

Figure 5. pH sensor installation in prefabricated panel

Figure 5. pH sensor installation in prefabricated panel

Sensors send signals to pH transmitters, which present the information to the control system. The transmitter should be easy to use; for example, just a few keypad manipulations should be sufficient to perform calibrations without having to use the instruction manual each time a calibration is performed. The transmitter should also provide sensor diagnostics to alert the user to the sensor state and deploy alarms or warnings should the sensor start to deviate from configured parameters.

Modern transmitters can have virtually any desired output from 4–20 mA to relay/alarm contacts to multiple digital communication outputs such as HART, FOUNDATION Fieldbus, Profibus PA, or EtherNet/IP. Many pH transmitters have an integrated Web server, allowing remote users to access the transmitter from any Web browser.

Conclusion

Work with the manufacturer to select the best pH sensor for your application. If possible, look for the latest in technology for both the sensor style (junction and glass formulation) and the sensor’s signal transmission methodology (i.e., analog vs. digital).

Usually, no two sensors within a single manufacturer’s portfolio can realistically serve the same application. There can be big differences in sensor design/construction for a sensor that is used in 10 µS/cm service as compared to a sensor designed for 1.0 to 2.0 µS/cm service.

Make sure pH sensor cables and connectors are specified correctly for the distances involved and the environment in which they will be used, and keep them free of moisture and corrosion. Pay attention to the materials used to mount the pH sensor and to the importance of stability in the flow rates past the sensor. Make sure the sensor is easily accessible for calibration and general maintenance. Make sure trained resources are available to maintain the pH sensors (cleaning and calibration) at the manufacturer’s suggested intervals.

If these steps are followed, accurate and repeatable pH measurements can be made in ultrapure water, leading to improved operations, reduced maintenance, and increased uptime.

About the Author
Fred KohlmannFred Kohlmann is Midwest business manager for analytical products with Endress+Hauser. Since 1976, he has been involved in engineering, design service, marketing, and sales of online analytical water quality and process control instrumentation.
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A version of this article originally was published at InTech magazine.

Click here to read Fred Kohlmann’s article on pH measurement of ultrapure water at InTech magazine.

Exploring the Global Shale Gas Initiative—Potential opportunities for ISA

Exploring the Global Shale Gas Initiative—Potential opportunities for ISA

This post is authored by Peggie Koon, president of ISA 2014.

If you look at any of the reports on energy or happen to browse the Energy Information Administration’s (EIA) website (www.eia.gov), you will see a large number of links to articles about the rapid growth of shale gas and tight oil. In fact, Natural Gas - Shale Gas road signPresident Obama, in his State of the Union address, talked “about the role shale gas can play in providing clean, reasonably-priced domestic energy.” But shale gas is not just a game changer for the US; globally, the rapid growth of shale gas production has tremendous implications for energy production and consumption.

At the ISA Executive Summit held in Greensboro, NC earlier this year, Society leaders identified the growing global demand for energy as one of 10 game changing trend rivers impacting the future of the automation industry and ISA. We also recognized the rapid growth of shale gas, its impact on the cost and consumption of natural gas, and the potential shale gas opportunity for ISA.

In this article we will review basic shale gas concepts, take a look at the global opportunity, touch briefly on new technologies being used, and look at environmental impacts. Finally, we’ll pose a few questions: How might ISA engage with this industry/market? Are there potential training and/or workforce development opportunities for ISA related to shale gas or other unconventional energy resources? What else might ISA do?

What is shale gas? According to the Energy Information Administration or EIA, shale gas is natural gas (primarily methane) which is trapped inside formations of shale. Shales are fine grained sedimentary rocks that may be rich sources of natural gas and petroleum. (http://energy.gov/articles/producing-natural-gas-shale)

How were these formations formed? Geologists believe that during the Devonian period of Earth’s history (300-400 million years ago) shale formations were formed…“Shales were deposited as fine silt and clay particles at the bottom of relatively enclosed bodies of water.” Around the same time forests were being formed on land from primitive plants and the first amphibians appeared. “Some of the methane that formed from the organic matter buried with the sediments escaped into sandy rock layers adjacent to the shales, forming conventional accumulations of natural gas which are relatively easy to extract. But some of it remained locked in the tight, low permeability shale layers, becoming shale gas.” (http://www.energy.gov/sites/prod/files/2013/04/f0/what_is_shale_gas.pdf)

How is shale gas recovered? Shale gas is recovered from shale formations using horizontal drilling and hydraulic fracturing or “fracking.” (http://www.eia.gov/energy_in_brief/article/about_shale_gas.cfm)

Diagram of a Typical Hydraulic Fracturing Operation

Diagram of a Typical Hydraulic Fracturing Operation

The combination of hydraulic fracking and horizontal drilling has transformed organic-rich shales that were previously unproductive into some of the largest, most productive natural gas fields in the world. “The Marcellus ShaleUtica ShaleBarnett ShaleEagle Ford Shale and Bakken Formation are examples of previously unproductive rock units that have been converted into fantastic gas or oil fields by hydraulic fracturing.” www.eia.gov

What shale gas resources are available globally? Advanced Resources International, Inc. (ARI) was commissioned by the Energy Information Administration (EIA) to complete an initial assessment of international shale gas resources. The report looked at almost 70 shale gas formations in 48 basins located in 32 countries and showed reserves of 6,622 trillion cubic feet of technically recoverable shale gas in the 32 countries analyzed. The map below shows the location of these basins and the regions analyzed in the study. For the full report, go to: http://geology.com/energy/world-shale-gas/.

International shale gas resources

Why is this important? Why should you care? Here’s a fast fact to remember: According to the EIA, just 1 trillion cubic feet of natural gas is enough to heat 15 million homes for one year, generate 100 billion kilowatt hours of electricity, or fuel 12 million natural-gas-fired vehicles for one year.

And by 2035, the EIA projects that shale gas production will rise to 13.6 trillion cubic feet, representing nearly half of all US natural gas production. (www.eia.gov)

2035 shale gas production

What new shale gas technologies are available related to hydraulic fracking?

In April of this year, I attended the NAE-AAES Convocation of Professional Engineering Societies in Washington, DC. In his presentation, Dr. Jeff Spath, 2014 SPE president, Schlumberger Limited, talked about new technological advances for unconventional energy resources, including:

  • Wellbore Placement & Geologic Steering – Technology has taken us from geometric to geologic forms of drilling, optimizing drilling of the well to the “sweet spot” using geologic steering
  • Electromagnetic look ahead drilling – Allows us to look ahead of the drill bit 10 to 60 feet away
  • Multi-stage fracturing – Allows us to increase contact between the well and flow from 315 sq. ft. to 160K sq. ft. using single stage fracking to 2.4M sq. ft. with Multi-stage fracking
  • Micro seismic monitoring/interpretation – Allows us to listen to the horizontal wells fractured, gives us an acoustic measurement plus visualization of the fractures, and allows us to optimize the way we take advantage of the flow. (https://www.nae.edu/File.aspx?id=113225) The technology combines subsurface sensors with powerful data collection and analysis software torecord the myriad of tiny microseisms (or micro earthquakes) that occur as fluid is pumped into a well bore, splitting or fracturing the subsurface rock formation holding the natural gas or oil. The individual locations of these micro seismic events are mapped to create an image of the fracture locations. To monitor each of these small events, high detection sensitivity devices are used. In addition to improving efficiency, the use of these systems also allows us to reduce the environmental impact of fracking. (http://www.ussensorsystems.com/oil-hydro.html)

Another hot topic of discussion was the potential use of liquid CO2 to replace water in the fracking process. Mr. C. Michael Ming, P.E., general manager, Oil & Gas Technology Center, GE Global Research, spoke to us about Unconventional Resources & State of R&D. Michael said we are in “the Age of Gas,” stating that natural gas is taking a larger role in the global energy mix because it’s affordable, reliable, and dispatchable. He talked about the research and development effort that is taking in place in these areas using technologiesthat are better, cheaper, faster, safer, cleaner, and smarter:

  • Production Systems
  • Well Construction
  • Energy Systems
  • Water Treatment
  • CO2 EOR & Fracturing (enhanced oil recovery and to replace water in fracturing)

See the presentation at: https://www.nae.edu/File.aspx?id=113229.

Recently, GE, which is studying the issue under a $10 billion research program, stated that “carbon dioxide, used for years to force crude oil out of old wells, likely will not replace water in fracking anytime soon because of technical challenges and limited infrastructure”.

GE is making a push into oilfield technology and is studying how a chilled form of CO2 known as a “super-critical fluid”—which is neither a liquid nor a solid—could be used as the new industry standard for hydraulic fracturing, (or fracking). The company is working on the project with Norwegian oil and gas producer Statoil ASA as part of GE’s ecomagination program, a program that focuses on gas turbine efficiency, wind blade design and other energy projects.(http://www.reuters.com/article/2014/04/07/generalelectric-fracking-carbon-idUSL1N0MT1HN20140407)

What about shale gas production and the environment?
Mr. Scott Anderson, senior policy advisory, Environmental Defense Fund, talked about eight risk areas associated with hydraulic fracking. The eight risks mentioned were:

  1. Well integrity – There are 136 elements critical to well integrity. Lack of well integrity can pollute water or cause leaking to the environment during construction and for lifetime.
  2. Induced Seismicity – Fracking can cause earthquakes. The earthquakes are caused by injection of fluid (resulting in 40 x increases in earthquakes that measure 4.0 on the Richter scale) and 2.0 quakes.
  3. Surface erosion – Fracking causes erosion of the soil.
  4. Water Use – Excessive use of water in the fracking process is a drain on resources.
  5. Surface spills – Waste from fracking can affect ground water.
  6. Recycling Risks – Due to storage, new forms of transportation, handling of residual waste streams, there are recycling risks.
  7. Air quality – While clear methane emissions are not so high to affect greenhouse advantages, air toxins, and fugitive methanes are by products of fracking.
  8. Infrastructure environmental impact – There can also be increased noise, dust, increased traffic, traffic congestion, and related fatalities. (https://www.nae.edu/Projects/Events/71511/113103/113105.aspx)

These risks are also cited by the EIA a list of potential environmental concerns related to hydraulic fracturing for shale gas since the fracturing of wells requires large amounts of water and produces large amounts of wastewater. Some of these concerns include:

  • Significant use of water for shale gas production may affect the availability of water for other uses and can affect aquatic habitats.
  • Hydraulic fracturing fluid may contain potentially hazardous chemicals. If mismanaged, these materials can be released by spills, leaks, faulty well construction, or other exposure pathways, which may contaminate surrounding areas.
  • Wastewater from fracturing may contain dissolved chemicals and other contaminants that could require treatment before disposal or reuse. Wastewater treatment and disposal because of the quantities of water used and the complexities inherent in treating some of the wastewater components, treatment and disposal is an important and challenging issue.
  • Hydraulic fracturing causes small earthquakes, but they are almost always too small to be a safety concern (reference the United States Geological Survey). Fracking fluids and formation waters (wastewater) are returned to the surface. The injection of wastewater into the subsurface can cause earthquakes that are large enough to be felt and may cause damage.” (http://www.eia.gov/energy_in_brief/article/about_shale_gas.cfm)

“If we did all the things we are capable of, we would literally astound ourselves” Thomas Edison

What are the implications for ISA? One of ISA’s strategic goals is to look at Big Data, to use analytics so that ISA’s products and services are market driven.

For the US, the EIA’s report “Outlook for U.S. shale oil & gas” projects that:

  • Shale gas will lead the growth in total gas production through 2040 to reach half of US output
  • Natural gas prices will remain well below crude oil prices
  • Natural gas consumption growth driven by electric power, industrial, and transportation use
  • Manufacturing output and natural gas use will grow with lower natural gas prices
  • Rapid growth of natural gas use in the transportation sector, especially in freight trucks
  • US becomes a net exporter of natural gas in the near future
  • Energy-related CO2 emissions remain below 2005 levels for the forecast period

Read the full report at www.eia.gov.

While I have not researched the implications for each of the 32 countries included in the EIA assessment, ISA might begin by looking at the data to understand how this phenomenal growth in shale gas and tight oil affects the automation industry, not just in the US but around the globe.

Are there opportunities for ISA to provide training, certifications, certificate programs, or standards related to shale gas production, water and wastewater, leak detection and repair, or micro seismic hydrofrack monitoring? Do we have existing products and services that can be applied to shale? Are there opportunities for ISA to develop new standards, products, and services related to shale gas or tight oil? What else might ISA do?

If you are engaged in shale gas and tight oil initiatives and are interested in helping to investigate the shale gas opportunity for ISA, please let Society leadership know. Contact me at president@isa.org.

About the Author
Peggie Koon_2Peggie Koon, Ph.D., is vice president of audience at Chronicle Media and The Augusta Chronicle, which are part of Morris Publishing Group, LLC, a privately held media company based in Augusta, Ga. Prior to joining Morris, Peggie spent more than 25 years developing IT systems for process automation and process con–trol in a variety of industries, including automotive, nuclear defense, aerospace, nuclear reprocessing, thermal ceramics and textiles. Peggie assumed her first ISA leadership position in 1996 as membership chair of the Management Division and has held a variety of prominent leadership roles in the Society. She earned a bachelor’s degree in mathematics from Smith College in Northampton, Mass. and completed graduate studies in industrial and systems engineering at the Georgia Institute of Technology. She received a doctorate in management information systems from Kennedy Western University in Cheyenne, Wyo.
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A version of this article also has been published in ISA Insights.

Biofuels: Good, But How Good?

This post is written by Thomas W. Kerlin, author of the book Future Energy: Opportunities and Challenges. To learn more on this topic and preview a free chapter from the book, please see the link at the bottom of this post.

Plant matter can be converted Future Energyinto liquid fuel that can serve as a replacement for oil-based fuel. But how does it work and how much production is feasible?

Plants convert carbon dioxide and water into sugar via photosynthesis using energy from the sun. The sugar undergoes further transformations within the plant. Carbohydrates, compounds composed entirely of carbon, hydrogen and oxygen, are produced. They are large molecular chains made up of sugar links. Carbohydrates produced include starch, cellulose and hemicellulose. Lignin, a high molecular weight polymer is also produced.

To make biofuels, the idea is to rearrange the components of the biomass to yield a new compound that can serve as a fuel. Enzymes, proteins that catalyze biochemical reactions, are capable of facilitating the desired reactions in carbohydrates. Common and inexpensive enzymes exist for converting starch into ethanol. Practical enzymatic conversion of cellulose and hemicellulose is not yet available, but it is expected that genetic engineering will yield suitable new enzymes. Chemical and thermochemical processes for converting biomass (including lignin) into liquid biofuel also exist.

But ethanol is not the only fuel that can be made from biomass. For example, butanol, a fuel with more desirable properties than ethanol can be produced enzymatically and hydrocarbons can be produced thermochemically. Processes such as these are well known, but are not currently competitive with enzymatic ethanol production from carbohydrates. Also, some plants produce triglycerides that can be used as fuel, either directly or after chemical processing by transesterification.

So what limits biofuel production? First and foremost is the land required. Fortunately, estimating the energy in biomass is quite simple. Terrestrial plants have energy content (BTU per dry ton) that falls in a narrow range. Plant yields (dry tons per acre) also fall in a narrow range. So it is simple to calculate the range of possible energy contained in the biomass per acre of land involved. Then only a fraction of the plant energy remains in the biofuel produced from the biomass.

The usual metric for considerations of large energy production is the Quad, defined a one quadrillion or 1015 BTU. The land required for producing a Quad of energy in biofuel ranges from 10 to 45 million acres depending on assumptions about plant energy content, plant yields and biomass-to-biofuel conversion efficiency. The United States uses around 35 Quads of oil-based energy per year (27 Quads for transportation). Producing enough biofuel to replace current consumption of oil would require hundreds of million acres. The total area of the lower forty-eight states is 1900 million acres and cropland is 441 million acres. Either production of biomass for biofuel on dedicated land or collecting waste biomass for conversion requires more land than is feasible for replacing current oil use totally.

So now we know that biofuels cannot replace current oil use totally. In fact, they cannot even come close.

There are other issues related to biofuel use. These include competition with food production, building a new production and delivery infrastructure, effects on soil fertility, adaptation to using biofuel instead of oil-based fuel in engines and other equipment and cost.

Biofuel use can make a modest contribution to liquid fuel needs, it can help reduce imports, it can create domestic jobs, but it cannot begin to supply total future liquid fuel needs.

To learn more on this topic and preview a free chapter from the book, click here.
About the Author

Tom Kerlin retired as head of the Nuclear Engineering Department at the University of Tennessee in 1998, after serving on the faculty for 33 years. His professional interests include instrumentation, nuclear reactor simulation, and dynamic testing for model validation. He has published extensively on these topics. In addition to his university service, Dr. Kerlin founded a spin-off company, Analysis and Measurement Services Corp., to provide the nuclear industry with the testing capability that he invented for safety system sensors. Dr. Kerlin’s method has been used hundreds of times in nuclear power plants in the U.S. and around the world. Upon retiring, Dr. Kerlin studied the literature on energy production and use and concluded that there was a need for a comprehensive book on our future options that even non-specialists would understand. His book is the result.

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