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A riddle wrapped inside an enigma
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2019 Deloitte Insights series, “Deciphering the performance puzzle in shales: Moving the U.S. shale revolution forward,” tells a well-known, but nevertheless hard-to-fully-take-in tale of rags to riches as an energy-dependent United States, in the span of a mere decade, transforms into a global energy giant. “The advent and commercialization of hydraulic fracturing and horizontal drilling beginning in the Barnett Shale paved the way for rapid expansion in unconventionals starting in 2005,” says the Deloitte article. The latest U.S. reserve estimates are pegged at 1,280 Tcf of shale gas and 112 billion barrels of tight oil. Deloitte maintains that the shales have “altered the entire oil & gas landscape, with the United States now projected to be energy independent by 2020. By mid-2019, U.S. tight oil production reached 8.5 million barrels per day or almost 10% of the world’s output.” What was wrought Shales are organic mudstones consisting of silt and clay that have a complex and heterogenous mineralogic accumulation and thickness, require custom engineering designs and completion stimulations, and are strongly guided by many above-surface planning and efficiency measures. Drilling, completing, and producing shale or tight oil & gas wells has always been both an art and a science, says a 2017 paper from the Oxford Institute for Energy Studies, “Completion Design Changes and the Impact on U.S. Shale Well Productivity”. Given a sub-$60 oil price environment, the paper goes on to say, this has never been truer. ”A combination of science, technological advancement, and brute force experimentation has led to broad productivity gains across the shale patch.” One example is the reduction in speed to total depth time when drilling, coupled with increased drilling precision. However, the paper goes on to say, “the most meaningful advances made during the downturn are
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KEVIN PARKER EDITOR
related to completion designs. Operators and service companies continue to experiment with and tweak completion designs, usually resulting in positive outcomes. The use of greater sand (proppant) and water (fluid) volumes has paved the way to productivity gains in multiple plays and is probably the single largest contributor to recent productivity advances.” What happens deep beneath the earth, however, remains something of a mystery, because the specific factors contributing to these gains are far less well understood, according to the Oxford Institute paper: “It is not the gains themselves that are in dispute, but what exactly is occurring beneath the surface to make these gains possible that remains subject to vigorous debate.” Look ahead What’s been happening isn’t a matter of debate for the folks at Deloitte, however. Operators, with the help of service companies, “have made huge strides in reducing their days per foot or lowering the shale cycle time by an average of 100 days. The planning and efficiency index has improved by 12 percent over the past five years.” One area where debate continues is the relationship between engineering and completion intensity, including increased proppant loading. While the Oxford Institute paper says the relationship between increased proppant and additional productivity are largely accepted, Deloitte says the higher intensity designs and simulations have led to diminishing results. From 2016 to 2018, almost 40% of oil & gas wells with high completion intensity ended up with below average productivity, Deloitte says. The conclusion: operations will continue to tweak their methods. OG
I NSIDE EDITOR’S COMMENT 2
A riddle wrapped inside an enigma
FEATURES 4
Machine learning at scale will be the norm Engineering ranks said to embrace the emerging discipline
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HART increasingly used for quick diagnostics Pluggable disconnect terminals for process engineering control systems
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Develop a full understanding of riser system health Digital elements of an asset integrity program described
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Pumps that thrive under pressure The evolution of hydraulic transmission technology in the pressure pumping market
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Maximize production by monitoring erosion Data from complementary monitoring technologies enable maximized production rates, even with entrained solids
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Products of the year: Award winners recognized Equipment, software solutions get the thumbs up
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An immutable ledger enables multi-party operations Put settlement disputes to bed and ensure multiparty accountability
OIL&GAS ENGINEERING DECEMBER 2019 • 3
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THE AGE OF ANALYTICS
Machine learning at scale will be the norm Engineering ranks said to embrace the emerging discipline By Kevin Parker
been a ‘ We’ve little surprised at the sheer volume of demand.
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n September, Baker Hughes Co. and C3.ai launched BHC3 Reliability, the first artificial intelligence (AI) software application developed by the BakerHughesC3.ai joint venture. More recently, Baker Hughes, C3.ai and Microsoft in November announced an alliance to make adoption of advanced analytics easier by bringing together cloud infrastructure, an AI platform and domain-specific applications. “Use of analytics, machine learning and artificial intelligence is not new to the oil & gas industries. But today, we’ve reached an inflection point, to deploy these technologies at scale,” said Dan Brennan, SVP & COO, BakerHughesC3.ai. Baker Hughes is a nearly $23 billion provider of integrated oilfield products, services and digital solutions. C3.ai is an AI software provider. The core of the C3.ai offering is a model-driven AI architecture that enhances data science and application development. In June the two companies announced a joint venture to combine Baker Hughes expertise with C3.ai’s AI software suite, for application in the oil & gas industry. BHC3 Reliability machine-learning models identify anomalous conditions that lead to equipment failure and process upsets. Application alerts enable proactive action by operators. BHC3 Reliability can scale to assets and processes across offshore and onshore platforms, compressor stations, refineries, and petrochemical plants, reducing downtime and increasing productivity. “If you look at the not-too-distant past,” Brennan said, “a lot of investment went into automating facilities to enable things like condition monitoring to reduce non-productive time. Extensive use was made of physics-based and rules-based models to better understand equipment operation. Therefore, we’re at a different point of maturity today, where more than 40% of unplanned downtime originates from non-critical equipment, which even today is not highly instrumented.“
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Things and kinds of things The kinds of analytics include principles-driven and data-driven, with two kinds of each. Physics-based analytics incorporate the physical and thermodynamics laws of how things work, while rules-based analysis is a kind of principles-driven analysis based on observation and domain expertise, including failure mode effect analysis (FMEA). On the other hand, data-driven analytics include, first, statistical models based on techniques like linear and other type regression, and second, advanced analytics that include artificial intelligence and machine learning, often based on pattern recognition. Roughly put, the domain of principles-driven analytics are the pumps, heat exchangers and myriad other equipment types whose workings are well understood by the engineering community. Root-cause analyses are often part of the picture. On the other hand, the realm of machine learning and artificial intelligence is the complex problems and to-be-discovered challenges native to process, plantwide and enterprise systems, where custom configurations of complex systems lead to unknowns. Thus, while physics-based models still play a crucial role, Brennan said, that’s being augmented by a data-based approach, to better understand, for example, what a normal operating range is, or, drilling down in detail, to better understand the correlations involved. But while machine learning may uncover otherwise unrecognized correlations, it’s not necessarily able to recognize cause-and-effect relationships. One aspect of scale is the data amounts involved. A machine learning model can exist for any given valve or pump, and for every instance of it, which may involve hundreds or even thousands of instances, or it may be looking at a system of systems.
“The models may be used to better understand how equipment performance correlated with past events, such as changes in operating conditions like a change of feed stocks. In many instances, what’s important is that the users are gaining a unified, federated view of the data. They’re gaining visibility into a data set that they would otherwise struggle to get their arms around,” said Brennan. The human dimension One issue often part of discussions related to machine learning and artificial intelligence is the relationship between domain expertise that the engineering community brings to bear and the work of data engineers and data scientists who better understand the ideal world of mathematical statistics. “What you want to avoid is a polarized view,” Brennan said. “Bear in mind that physics-based models still play an important role here and the background the engineering community commands is critical to success. There is a certain ‘dialect’ spoken by those in the oil & gas industries.” What’s most wanted today in these advanced technology endeavors is compressed time to value, said Brennan. “You don’t want to spend 60 days explaining the vocabulary to the uninitiated. It’s the engineers who can quickly determine how to model a process based on the probability or consequences of failure.” An example of compressed time to value, notes Brennan, is that Reliability was launched within 90 days of Baker Hughes announcing the partnership. “When you put the two kinds of people together things accelerate.” Moreover, engineers are exhibiting real interest in involvement in advanced analytics efforts. “Fifteen years ago there was no such thing a college-degree major in data science. Today there is. However, it’s interesting the large number of engineers’ mid-career interested in engaging in data science-related work. For the younger engineers just embarking on careers, providing access to these types of tools and systems is a good recruiting tool. This includes our relationship with Nvidia [developer of graphical processing units], which has been a good draw and a compelling proposition,” Brennan said. Connelly said that Baker Hughes is pleased that 50 of its employees have gone through
C3 training. “We’re deploying them in areas as diverse as inventory management and receivables and collectibles. We’ve been a little surprised at the sheer volume of demand for resources to deploy. What concerns us amidst this activity is forging the right governance model for command and control.” Finally, application development is moving to low-code or no-code environments. To date, one challenge with machine learning is moving something developed in the lab to operations scale, especially when operations change rapidly. “You do encounter citizen data scientists building out analytics,” Brennan said. Adding Microsoft and its cloud platform, Azure, into the mix is another means to speed time to value. Microsoft platforms already occupy a substantial footprint in industrial enterprises. Besides Microsoft’s data center expertise, Azure makes available microservices that including Power BI embedded in Azure for data set visualization; Azure Kubernates Service for containerization and moving legacy applications to the cloud; and Cognitive ML services.
than 40% ‘ More of unplanned downtime originates from non-critical equipment.
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Other advancing technologies The Baker Hughes news release announcing availability of BHC3 Reliability mentions several other technologies as bearing on the company’s efforts related to machine learning use in oil & gas industries. Avitas Systems provides solutions for achieving asset integrity management through robotics inspection, including the use of drones, and analytics that incorporate computer vision, machine learning and physics-based modeling. In just one example of the techniques involved, machine vision can be applied to photo-realistic models made from RGB and IR images captured using drones, such as of a refinery. Computer vision techniques can be used to associate image and video findings back to an asset’s 3D model, to detect anomalies. Natural language processing comes into play when one of the inputs into a machine learning model are maintenance records, constituting a species of unstructured data, generated by humans in natural languages such as English.OG Kevin Parker is the editor for Oil & Gas Engineering. OIL&GAS ENGINEERING DECEMBEr 2019 • 5
STANDARDS & PROTOCOLS
HART increasingly used for quick diagnostics Pluggable disconnect terminals for process engineering control systems By Alan Sappe’ and Torsten Schloo
Figure 1: In the chemical and process industries, the cost of technology is rising, especially given tighter process schedules — pluggable test disconnect terminals simplify servicing and maintenance. All graphics courtesy: Phoenix Contact
“M
ore complex, more compact, more efficient” – is the credo for control system engineers in the oil & gas, chemical, and process industries. This view also accelerates efforts to squeeze production into tighter and tighter process schedules. Over the last few years, engineers in the petrochemical and process industries have tested many new ways to make production quicker, cheaper, and more flexible — quite successfully in some cases. These advances help the industry recover relatively quickly from cyclical downturns. Modularization, industrial automation, retrofitting, and system expansion all contribute to industry success. These tendencies have also facilitated the increased use of Highway Addressable Remote Transducer (HART) communication protocolcapable sensors and control valves. This protocol uses traditional 4-20 mA current loop as a transmission medium for a modulated data transmission signal in accordance with the Bell 202 FSK standard, where communication is conducted with signal sequences of varying frequencies alternating between command and response on simple twisted-pair cables. This keeps implementation costs down, without affecting the actual analog measurement signal. It allows the system
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to transmit multiple pieces of information and makes it possible to diagnose problems or configure devices remotely. Over the past 25 years, countless HART devices have been installed in applications related to flow, pressure, temperature, and fill-level measurement. In many cases, only the 4 - 20 mA signal is permanently connected, while HART data is only accessed during start-up or troubleshooting. What are disconnect terminals? HART is used with several sensors for measuring temperatures, pressures, vacuums, filling levels, distances, conductivities, densities, and pH values. Valves, servomotors, inputs and outputs of all varieties, and analog values are also controlled using HART. This can be done in three ways: 1. Readjustment and calibration of measurement values 2. Troubleshooting in complex systems 3. Parameterization or querying of device configurations using a computer. It is often necessary to connect measuring or diagnostic devices to a current loop — to measure the parameters that the sensors receive and to evaluate the switching states or system parameters. In conventional control systems that do not use a current loop for data communication, a short signal interruption does not necessarily cause any problems. But if the current loop is also the transmission medium, interruption causes a break in communication with the HART modem and a system error message is sent. That explains the indispensable value of interruptionfree connection for HART-controlled systems. Innovative and rugged disconnect terminals have test sockets on each side of the disconnect point where a measuring device is inserted before the disconnect knife or switch is opened. This action must be completed before the measurement. Test disconnects make that action easier for technicians because the disconnect zone is
designed as a contact spring. The contact spring is automatically disconnected when a suitable test adapter or probe is inserted. The plug’s disconnect pin ensures that capacitive contact is made with the test socket. This facilitates safe, interruptionfree connections so that HART communication is not impaired during the measurement process. Reduce downtime Advantages of a pluggable disconnect terminal include ease of operation, troubleshooting efficacy and space savings. Any signal conducted through such a terminal can be easily evaluated by quickly plugging in the test probe. This is particularly convenient during troubleshooting. When technicians are working with conventional disconnect terminals, they must ensure that the test lines are secured and do not slip. Testing lines also often impair the opening and closing of the disconnect knife blade. Special disconnect terminals, with widths as narrow as 6.2 mm, can be installed and operated in compact spaces within the control system. It is also important to avoid errors due to interruption of the HART protocol. Such errors would consume a great deal of time and require unnecessary space in error message logs. Finally, responses can be conveniently tested at the disconnect terminal with analysis and diagnostic devices. Eliminate errors, calibrate readings Despite simple bus topology, system faults may still require repeated service calls. During such calls, technicians need quick, easy access to the signals by means of multimeters, diagnostic tools, and current loop profile calibrators. Common causes of faults include: • Substandard connections or corrosion at the connection point in the complex system structure, resulting in inaccurate measurement values • Overloaded 24 V voltage supplies, leading to an undefined sensor or actuator signal state • Incorrectly interpreted input and output signals that disrupt the process • Noisy measurement signals from the signal transmitters that make it difficult to adhere to process schedules. Pluggable disconnect terminals provide welltested electronic component technology. The clamping sleeve’s Reakdyn design ensures a
self-locking screw connection, and nickel-plated clamping sleeves and silver-plated contact springs ensure stable, low transition resistances. The spring’s base material is a hard copper alloy — the surface is passivated and greased to better protect against corrosion. These disconnect terminals are shock- and vibration-tested according to DIN EN 61373, with a Category 1B certification. The terminal withstands salt spray atmospheres, according to industry standards DIN EN 60068-211, with a test duration of 144 hours, as well as atmospheres containing sulfur dioxide, according to DIN EN 50018. Defined switching behavior To address switching applications of a disconnect terminal, some manufacturers offer three test disconnect adapters available in multiple colors. This allows either capacitive (red) or delayed (green) disconnection based on the differences in the disconnect pins. For a simple disconnect procedure, there are service disconnection plugs, which do not provide power pick-off terminals (gray). Building a bank of multiple blocks and using simple wire jumpers make it possible to construct suitable circuits for use with current and capacitor voltage transformers. This allows current transformers to be capacitively short-circuited. With current ratings of up to 10 A/300 V per UL 508A and 1059 standards, and a maximum of 6 mm² clamping capacity, test disconnect terminals cover a large portion of process engineering requirements. For currents up to 30 A, more powerful products that feature inline test disconnectors can be used. In addition to disconnect terminals, a comprehensive HART solution typically includes components such as signal isolators, surge protection devices, multiplexers, and USB modems. By providing a cost-effective, permanent connection to HART data, process engineers can optimize maintenance and system operating times. OG Alan Sappe’ is product marketing manager at Phoenix Contact USA, with more than 20 years’ experience in industrial connectivity and control systems. Torsten Schloo is product marketing manager at Phoenix Contact headquarters in Blomberg, Germany, with 10 years of experience in planning and maintenance of robot-assisted manufacturing systems and another 20 years in industrial connection technology. OIL&GAS ENGINEERING DECEMBER 2019 • 7
OFFSHORE DRILLING
Develop a full understanding of riser system health Digital elements of an asset integrity program described By Kenneth Bhalla
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he drilling riser on a mobile offshore drilling unit (MODU) features a conduit between the drilling rig and well system that serves a critical role within the system. Typically comprised of a series of connected 75-feet to 90-feet long riser joints, the riser is the main conduit to drill through, connecting to the top of the blow-out preventer (BOP), which is latched to the wellhead and casing system on the seafloor. It is essential to develop a full understanding of riser system health to ensure that all riser damage and associated risks are captured and quantified accurately based on past loading history and any future loading states. Annual inspection rotation Drilling riser joints are typically inspected at five-year intervals. This is usually performed by rotating 20% of the riser joints onshore every year to be dis-assembled and inspected. Many costly and time-consuming boat trips from the MODU to onshore facilities are required for this procedure, in addition to trucking the riser to the inspection facility once onshore. Approximately 20 riser joints from each riser system are transported by boat and one riser per truck to the inspection facility each year, making the logistics of performing a drilling riser joint inspection complex and costly. However, since the riser system experiences significant wear, erosion, corrosion, fatigue damage and seal damage during operations, this process has long been considered essential for tracking deterioration over time. Digital elements Invoking digital elements of a condition-based maintenance and monitoring program are ultimately meant to reduce both operational
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expenditures and capital expenditures, and to minimize and manage risk with accurate information pertaining to system health. The elements listed below form an Internet of Things (IoT) eco-system used to manage asset health: A physics-based digital twin of the asset drives the process. Sensor technology is designed and specified to understand: • The physical loading of the asset • The response of the asset. Data cleaning is used to characterize the asset loading and response measured by the sensors. Inspection techniques are used to create a living digital signature of the asset. Data science techniques such as artificial intelligence, machine learning, and deep learning are used with the sensor data and physics-based digital twin to characterize future response states from physical loading. The future response states can be verified by inspection. These elements or resources form the basis of a process that leads to: • Cost savings • Risk reduction through understanding of key performance indicators • Increased performance with additional data analytics. The process data resides on a dedicated information management system, which supports the user with inventory management data. Reliability, consistency, accuracy A condition-based maintenance system which leverages monitoring of riser systems with a laser-based inspection system, has been implemented with a new standard process, which is American Bureau of Shipping (ABS) approved.
Figure 1: Invoking digital elements of a conditionbased monitoring and maintenance program for drilling risers and are meant to reduce both operational and capital expenditures. Image courtesy: Stress Engineering
The aim is to empower drilling contractors to: • Reliably determine the condition of drilling riser joints • Consistently predict when vital components will require service • Accurately assess remaining component life. The approach uses a life-cycle conditionbased monitoring, maintenance and inspection system that can be deployed on an MODU, enabling resources to be deployed only when necessary. Since drilling riser joints may not be in continual use, it makes sense that maintenance periods should be usage or conditionbased instead of calendar-based. The solution consists of performing a baseline inspection on the riser joints to assess their present state; collecting the environmental and operating data when the rig is on- site drilling; and feeding the environmental and operating data into the digital twin. There is today no alternative technology available that brings together a digital twin of the riser system, onboard riser inspection and load monitoring of the riser to calibrate the digital twin, followed by a determination of actual loading, stresses and fatigue damage over each riser joint. Thus, it accurately assesses remaining life and allows targeted inspection. The technology can be used to predict when riser joints may be susceptible to damage.
Determining stress The drilling information, metocean conditions and riser data are collected to determine riser joint fatigue damage. The proprietary system determines stress and fatigue at any location in a riser system/wellhead/conductor casing via measurements from several accelerometers and angular rate sensors, placed at strategic locations along the riser, together with analytical riser mode-shape information. Because the only required online inputs are the dynamic riser response, top tension and mud weight, fatigue can be estimated without knowledge of the impinging currents or other forcing events. Vibration sensors and data-acquisition electronics are housed in the subsea vibration logger (SVDL), which is ABS approved. The data are then processed using patented technology that integrates a computer algorithm to synthesize stress estimates along the entire riser length using a database of riser dynamic modes. The estimates are then processed chronologically via rainflow counting to determine fatigue damage accumulated during a drilling riser campaign, thereby providing actionable information to the drilling crew. The data can also be imported into a 3D viewing system for finite-element analysis. Detailed measurements are collected, including vessel, metocean, drilling conditions and either real-time or stored load measurements during the drilling operation on the riser system using subsea vibration (SVDL) technology to assess fatigue damage. The sensors are chosen to accurately measure system response. The response process requires OIL&GAS ENGINEERING DECEMBER 2019 • 9
OFFSHORE DRILLING specialized data cleaning techniques to ensure that the asset response is characterized and interpreted correctly. A laser profilometry system is used to collect measurements on the inner diameter of the main bore and axillary lines, between wells to characterize the state of drilling riser joints. In addition, other nondestructive examination (NDE) techniques such as surface NDE, volumetric NDE and wall-thickness measurements are used to assess the health of the drilling riser joint. The SVDL can be installed individually by a ROV on riser joints, wellheads and BOPs in an ‘offline’ mode. In the offline mode, the recorded vibration data are retrieved after the measurement campaign and then processed offline to estimate stress and fatigue. A semi-analytical method is used to estimate wellhead fatigue damage directly using the measured BOP stack motion data. Analytical transfer functions are used to directly compute stress-time histories and fatigue damage at any location of interest in the drilling riser system. The offline fatigue monitoring system provides the operator with a useful tool to assess system integrity at any time during a drilling campaign. The semi-analytical method to compute fatigue from measured vibration provides rapid turnaround of raw data to fatigue consumption, enabling informed decisions to be made in adverse conditions. Physics-based digital twins Asset integrity management programs are dependent on a combination of laborintensive inspection, analysis and measured data. A digital twin is a digital replica of the physical asset, in this case the drilling riser system and MODU. This system’s digital representation provides the basis of how the asset responds under various operating conditions. The system digital twin integrates a computer model of the physical system together with response data of the system, and data analytics, to create a living digital simulation of the system as the asset undergoes various operations. A digital twin model of the global drilling riser and MODU has been developed and can be used to view the fatigue loading of the 10 • DECEMBER 2019 OIL&GAS ENGINEERING
actual drilling riser joints, as SVDLs collect data, the SVDL data is used to update the digital twin. The digital twin is designed to be an up-to-date and accurate copy of the drilling riser and MODU’s properties and response status. The digital twin also can be used for monitoring and diagnostics to optimize asset performance and utilization. The sensor data (SVDL, rig response and so fort) can be combined with historical data, human expertise and fleet and simulation learning to optimize performance and improve productivity. Cost reductions A drilling contractor deploying this program can expect to experience lower inspection costs, as major inspections are performed according to operating conditions rather than at set time intervals, thus leading to lower OPEX. Since fewer spares are required due to fewer instances of risers being out of service, the drilling contractor’s riser asset management is improved, and CAPEX is reduced. Lower logistics costs are experienced, with less call for risers being transported back and forth by boat. The reduction in complex logistics proves to be even more critical in remote operations. Final words Using a life cycle condition-based maintenance, monitoring and inspection system that can be deployed on the MODU, users remove uncertainties surrounding damage of riser joints. The owner is then able to determine whether a riser should be redeployed or replaced. The system is compatible with all present owners’ maintenance programs and ensures that maintenance requirements are supported with robust engineering. This is the only process that is ABS approved for condition-based monitoring of drilling riser systems. OG Kenneth Bhalla, Ph.D. C.Eng. MIMMM is chief technology officer, Stress Engineering Services. Kenneth oversees the entire product and service portfolio and leads efforts in developing a long-term technology strategy as Stress Engineering Services furthers its commitment to bringing innovation to the marketplace.
FRACKING APPLICATIONS
Pumps that thrive under pressure The evolution of hydraulic transmission technology in the pressure pumping market By Dean Bratel
Hydraulic transmission technology is evolving to keep up with the performance requirements for hydraulic fracturing applications like these SINOPEC rigs in China. In the U.S., the race to extract natural gas from the Marcellus shale has led to the development of more powerful fracking transmissions as production shifts away from shallow vertical wells. Images courtesy: Twin Disc
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racking technology is driving transformation of North American energy production capabilities. Since 2005, most of the increase in domestic natural gas production resulted from ongoing development of horizontal drilling and hydraulic fracturing technology. Producers developed more efficient ways to extract gas and crude oil from deposits of shale, sandstone, carbonate, and other geologic formations. The hydraulic transmission technology that fracking applications rely on has evolved to meet demanding and increasing performance and reliability requirements. The 30K-foot view All hydraulic transmissions operate on the same basic principles. Clutch operation is activated via hydraulic pressure. To shift, there is a sequence of activity in which a control system tells a solenoid to turn on or off, directing pressurized hydraulic fluid to various clutches within the transmission. In most cases, power is transmitted from the engine to the transmission through a torque converter, which is a hydrodynamic device that multiplies torque. These components help engines operate in the most efficient speed range, producing rated horsepower regardless of load demand.
For example, in a car, as soon as the accelerator is pressed, the torque converter is engaged in order to provide adequate power until the input shaft of the transmission reaches a certain speed. Once that happens, a clutch inside the torque converter is engaged, bypassing the hydraulic circuit and directly connecting the engine to the transmission. Hydraulic transmissions for fracking applications must be able to transmit tremendously high horsepower to the pumps. They must also be efficient, preventing the loss of power output as waste heat. Fracking applications must operate at top capacity in dirty, dusty and often hot environments. The transmissions must be designed to protect them from foreign materials. To reduce downtime, the transmissions must be designed to minimize the frequency of oil changes required. Hydraulic fracturing rigs are vulnerable to excessive vibration. Torsional vibrations and shock loads can cause harmful torque spikes, reducing the service life of the equipment. Fracking transmissions must be capable of withstanding these vibrations. Transmissions must also have long life and durability. Fracking sites now run longer stages for longer hours. In past years, frack pumps on a wellsite might only run for six hours at time. Now, they need to run 24 to 36 hours at a time. Case study: Universal Well When companies began extracting natural gas from the vast reserves found in the Marcellus Shale in the Appalachian Basin, it required equipment with higher-power pumps and engines than required for shallow vertical wells. This put greater performance demands on the transmissions involved. While upgrading its fracking fleet, Universal Well Services Inc., a provider of hydraulic fracturing services, needed a replacement transmission for its pressure pumping applications that would provide greater reliability and improved service OIL&GAS ENGINEERING DECEMBER 2019 • 11
FRACKING APPLICATIONS
Although traditional transmissions in oil & gas applications require use of hydraulic torque converters, today’s transmissions have a master clutch that eliminates the need for a converter and reduces the transmission’s footprint.
life. This required a drop-in replacement transmission that would be compact enough to fit in its fleet of existing fracking rigs while providing enough horsepower to meet the increased demands. Great Lakes Power Service Co., a power transmission distributor serving the Southeast, worked with Universal Well to find the best solution. The Great Lakes team recommended use of a purpose-built Twin Disc TA90-7500 fracking transmission, which consists of a 9-speed coaxial power-shift transmission that provides up to 2,600 HP and incorporates an advanced electronic control system. Designed to be smaller and requiring less complicated plumbing than other transmissions, the TA90-7500 could be more easily fit the fracking rigs. The transmissions proved durable. Over a five-year period, many of the transmissions saw up to 14,000 engine operating hours without failure. Twin Disc engineers used the lessons learned from working with the Universal Well applications and folded them into the next generation of the technology — the TA90-7600. This included the addition of a planetary reduction gear on the output of the 7500 to create a new transmission. Although traditional transmissions in oil & gas applications are required to use hydraulic torque converters, the TA90-7600 has a master clutch that eliminates need for the convertor. The master clutch, guided by the integrated control system, allows full power shifts to all the ranges without losing torque. Elimination of the torque converter reduces the required footprint for the transmissions. Changing demands As fracking technology evolves, hydraulic transmission technology will have to keep advancing. The market sector demands ever-smaller transmission units, challenging designers running up against the constraints of the laws of physics. Key to reducing the size of hydraulic transmissions is increased efficiency. The more completely a transmission transmits all energy coming out of the engine to the pump, the better. This means
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less generation of waste heat, allowing designers to reduce the size of the cooling components. Developing clutch technology that allows transmission of torque more effectively will boost system performance overall. Even something as mundane as the oil composition used within the transmissions is important. Advances in synthetic oil chemistry reduce the number of oil changes needed, allowing units to operate for longer periods of time without interruption. Importance of control systems During the past 10 years, many innovations in hydraulic transmission technology focused on the creation of increasingly sophisticated electronic control systems to direct the activation of clutches with the transmissions. The control systems can allow smarter operation of the transmissions and greater control of oil pressure. With smarter electronic controls, transmission performance can be fine-tuned, improving performance and reducing problems that can cut down on the unit’s lifespan. This can include managing potentially harmful torque spikes resulting from vibration and high loads. Although fracking applications share common characteristics in general, each has specific needs for how control systems are integrated within a rig’s rate controller. Electronic controls must prevent overspeed, shift shocks and reduce the effects of operator errors, limiting wear and tear on machine components. The best electronic control systems ensure safe shifting, avoiding potential harm to clutches, transmission or other equipment. This requires good communication between the unit’s rate controller and the transmission controller. Summing it up Hydraulics transmissions have been around for a very long time, but the demanding performance requirements of oil & gas production applications continue to drive technology innovations. Market pressures require development of smaller and more durable transmissions that provide evergreater amounts of horsepower to keep up with the advancement of fracking applications. OG Dean Bratel is a vice president at Twin Disc Inc., which designs, manufactures and sells marine and heavy-duty, off-highway power transmission equipment.
ASSET INTEGRITY MONITORING
Maximize production by monitoring erosion Data from two complementary monitoring technologies enable maximized production rates, even with high entrained solids By Jake Davies, Ph.D.
Figure 1: Continuous corrosion and erosion monitoring
T
he huge capital amounts required to build new oil & gas production assets, coupled with unpredictable commodity price changes, mean producers focus their attention less on new major projects and more on extracting maximum dollar from existing infrastructure and assets. While individual oil & gas producers can do little to affect prices received for their products, there are things they can do to reduce costs and maximize production. Whatever the market price, a higher production rate equals more revenue from assets. Because margins are tight, individual asset integrity can be the difference between incurring a loss and securing a profit. It’s not surprising that producers are shopping among suppliers looking for discounted opportunity crude oils and gas, but this has to be coupled with thrusting operational excellence back to the top of the corporate agenda. All possible options must focus on extracting maximum value from existing resources. Of course, optimized production must be achieved with investments that deliver fast payback. Substantial reductions or delays in CAPEX projects along with pressure to reduce OPEX mean payback for any outlay must be swift and clear. “Doing more with less,” is the mantra of the moment, and efforts are shifting towards generating maximum return from available resources.
information. Data that can deliver insight and actionable information is needed if operators are to make the right decisions and deliver desired outcomes. Fixed equipment integrity is one example where cohesive, high-quality and timely data is often lacking. On the one hand, the corrosive effect of produced fluids and the erosive impact of produced sand particles in oil & gas-produced streams is well understood. On the other, information about the impact of these corrosive or erosive materials on actual asset integrity is often absent. The solution is to monitor continuously for corrosion and erosion and use this information to improve operating efficiency (Figure 1). Sand entrained in oil & gas streams poses significant risk to production equipment because it is moving at high velocities inside fixed equipment and can eat away metal piping and equipment from the inside, with an effect like sand blasting. This erosion occurs inside of piping and equipment, making its effects extremely difficult to detect via exterior inspection. However, modern measurement techniques can detect both entrained sand and its impact on asset integrity. Figure 2: Sensors to monitor both the risk and the impact of sand erosion (metal loss) can be combined to help maximize production.
improve operations. All figures courtesy: Emerson
Supplying the Missing Data However, maximizing output from existing assets is a major challenge when dealing with incomplete or absent OIL&GAS ENGINEERING DECEMBER 2019 • 13
ASSET INTEGRITY MONITORING
Figure 3: Non-intrusive thickness monitoring wireless sensors are easy to install.
Figure 4: Wireless sensors were installed as part of a complete data-to-desk system, including powerful data visualization and analytics.
For best results, operators should seek data regarding sand erosion from a range of sources. In this case, it is best to measure both the risk (sand entrainment rate) and the impact (rate of metal loss). Since sand entrainment in any well is likely to vary over time, it is imperative that both the entrainment and the erosion rate are continuously monitored. Conveniently, measurement techniques for both are non-intrusive. Listening for trouble Acoustic sand detectors identify the presence of sand in the production flow by listening for the sound of solid particles hitting the piping’s insides. With careful calibration, the sand entrainment rate can be estimated. However, acoustic detectors cannot measure the impact of entrained sand on equipment integrity. Established manual inspection methods can intermittently measure pipe wall thickness, but due to the associated costs and safety risks, manual inspections are typically carried out at infrequent intervals, and can require production stoppage. What these solutions can’t do is provide an accurate, complete, and real-time picture of erosion levels. As a result, operators only have a snapshot of their assets’ integrity at best, and this data quickly becomes out of date. With this minimal information, it is almost impossible to predict whether fixed equipment is good for another five months or another five years. In addition, for a given sand entrainment rate, the erosion rate is expected to be proportional to the cube of flow rate.
14 • DECEMBER 2019 OIL&GAS ENGINEERING
Therefore, if sand entrainment is detected, the standard response of the operator is to reduce the production rate, or ‘choke’ the well. Thus, to protect asset integrity and mitigate risk of an infrastructure collapse, conservative production rates are the norm. Improved asset monitoring Now imagine the transformational effect of automated sensors permanently attached to strategic points in the infrastructure to take continuous, robust measurements of remaining pipe wall thickness. The sensors use wireless technology to send gathered data for analysis at a central, safe and convenient offshore or onshore location. Operators would gain immediate insight into what’s happening with fixed equipment at any given time, with no need for guesswork (Figure 2). Data quality improves because monitors are permanently installed with a frequency of measurement allowing operators to see equipment wall thickness changing as it happens. Operators see how the infrastructure responds to unpredictable and generally uncontrollable variables at work. They also see the effect of unexpected changes in temperature, flow rate, or other uncontrolled variables. This allows operators to assess what changes result from higher flow rates, and to understand the effects of erosion mitigation and corrosion inhibition strategies, and then adjust each as necessary for optimum output. These type tools give operators access to real-time data, enabling optimized operational decision-making and leading to improved asset uptime and increased profitability. These types of high-quality and field-proven solutions make a tangible difference to operator margins by ensuring the plant or asset is nearer maximum capability. Better monitoring maximizes One operator with multiple unmanned gas production platforms in the Caribbean Sea used a combination of acoustic detectors to monitor sand entrainment and Emerson Rosemount nonintrusive thickness monitoring sensors to monitor for metal loss (Figure 3). Using data from these instruments, the operator increased production by 12%. Validating the increased flow velocity did not unduly increase the erosion rate. With increases in production, the monitoring system paid for itself in a matter of days (Figure 4).
Another operator, this one working in shallow water offshore of Thailand, used the same combination of monitoring techniques to asses both the risk and impact of entrained sand. They were able to increase their production rate by 50 barrels per day, for a rapid return on investment. Onshore coal seam gas production activities in Queensland, Australia have an especially high level of solid entrainment. An operator in this area had experienced loss of containment issues at several well heads due to erosion caused by sand flows. The operator knew what wells were at elevated risk of solids production but lacked information about how risk varied over time, and whether solids were damaging production equipment. A solution again used the combination of acoustic detectors and ultrasonic thickness monitoring devices. The solution also included long-range wireless data backhaul to deliver monitoring information from the remote well-heads to a centralized team. The team evaluated the data and made decisions to optimize and maximize production based on solid entrainment flows, all while ensuring wellhead equipment was not being damaged from the inside. Reduced costs, increased revenue Using these technologies, operators are in a better position to create a cost-effective program for monitoring asset integrity. There is an instant saving by eliminating the need for frequent routine manual inspections, which can instead be performed by monitoring sensors, especially for offshore assets where cost of access is extreme, and a long-term gain from enhanced asset reliability and availability. Automated monitoring of asset integrity combined with appropriate data analysis also gives operators the confidence to drive their assets harder within the appropriate parameters. Of course, equipment integrity related to corrosion and erosion is only one element that operators are assessing in the face of lower oil & gas prices. It’s attracting attention, not least because it delivers results within a short timeframe and therefore an equally short payback period, often within days. It also taps into a wider movement by no means exclusive to oil & gas production. This is the era of digital transformation and technologies that gather, secure, analyze and present data in quick-to-understand formats. The ability to extract and exploit previously unavailable data is more than simply another cog in the innovation cycle. It is both a solid foundation for future developments and an enabler of long-term, strategic decision-making in the face of an unpredictable and volatile future. OG Jake Davies, Ph.D., is marketing director for Emerson’s Permasense corrosion and erosion monitoring products. He has been involved in development, deployment, and support of non-intrusive wireless corrosion and erosion monitoring systems since 2008. Jake holds a doctorate from Imperial College London, a Master of Engineering from Oxford University and an MBA from The Open University. OIL&GAS ENGINEERING DECEMBER 2019 • 15
Real World Examples On How To Optimize Production & Reduce Costs
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PRODUCT OF THE YEAR
Award winners recognized Equipment, software solutions get the thumbs up Oil & Gas Engineering’s annual product of the year awards recognize significant innovation and advancement in technologies and best practices. In this December issue we announce the award winners. To any observer, what first impresses is the sheer scale and scope of the oil & gas industries, entailing more information than anyone could absorb in a lifetime. The selections below demonstrate how incremental but telling innovation in automation and information technology is being applied to processes or equipment categories that have been with us for quite some time.
These innovations include a new generation of machinery management software for proactive monitoring of equipment, especially the rotating kind; digital twins for use in risk evaluation management; advances in pressure pumping and in portable data collection; and incorporation of machine learning into connection integrity evaluation. While what matters most is the efficacy of the solutions in the real world of dollars and cents, the satisfying of our collective curiosity about how things unfold pays for itself.
IIoT & process control
∠ GOLD AWARD WINNER Condition monitoring, diagnostics software The System 1 version 19.1 software platform offers a modern and intuitive interface that enables users to establish, manage and improve their plant-wide condition monitoring programs. Bently Nevada’s System 1 has achieved broad adoption around the world in process-intensive industries. The platform has been continuously enhanced since its launch and has been redesigned to meet the cybersecurity requirements, diagnostic expectations and user experience of engineers and information technology professionals. System 1 upgrades adhere to a bi-annual release rhythm with user-driven enhancements, expanded connectivity and compliance with the most recently updated operating systems and security patches.
https://bently.com
∠ SILVER AWARD WINNER
∠ BRONZE AWARD WINNER
Operational risk management software
Cyber threat detection software
Operational Risk Management (ORM) Digital Twin software brings together the data collected from enterprise systems, mobile applications, sensors and human-derived inputs as part of an Industrial Internet of Things (IIoT) strategy to produce a computer-generated risk map. This allows companies to obtain a simulated view of their operational risk in real time on SpheraCloud. The technology includes an early warning system that makes all risk exposure visible, prominent and available in real time. This is designed to help reduce organizations’ vulnerability to high-potential near-misses and major hazards. ORM Digital Twin technology allows companies to improve their risk management capabilities while improving productivity and managing costs.
Guardian version 18.5 protects control networks from cyber attacks and operational disruptions. It provides superior operational visibility and rapid detection of cyber threats, plus processes risks through a passive network traffic analysis. Guardian automatically discovers an entire industrial network, including assets, connections, protocols and topology. It monitors network communications and behavior for risks that threaten reliability and cybersecurity, and provides the information needed to respond quickly. Guardian delivers asset identification, network visualization and real-time monitoring, industrial control system (ICS) threat detection using a hybrid approach, enterprise-class scalability when deployed with the Central Management Console, and easy integration and sharing of ICS and cybersecurity information with information technology/operational technology infrastructure.
https://sphera.com
www.nozominetworks.com
16 • DECEMBER 2019 OIL&GAS ENGINEERING
Machines & Equipment
∠ GOLD AWARD WINNER Quintuplex frac pump The SPM EXL Frac Pump is a quintuplex pump with a rod load rating of 238,000 lbs., and is designed as a drop-in replacement for existing QWS 2500 pumps and other 2500 pumps. The SPM EXL Frac Pump’s frame is constructed with an integrated skid designed to reduce vibrations across the frame and increase stiffness, thus reducing stress on the weld. The frame also drastically reduces the number of internal groove welds to reduce cracking. All welds are located on the outside of the frame, making them more accessible. To address the higher stresses put on the gear system from high torque encountered when operating at high rod loads, the gears and pinions are redesigned utilizing the latest manufacturing techniques to provide greater surface area contact on the bull gears and reduce the risk of stripping them.
www.global.weir
∠ SILVER AWARD WINNER
∠ BRONZE AWARD WINNER
Portable data collector
Casing, tubular connection evaluator application
SCOUT200 version 19.1 is a smart, intrinsically safe and portable data collector that is fully supported by System 1 condition monitoring and diagnostic software. SCOUT200 integrates with the suite of portable and monitoring products that enables data analysis from a comprehensive suite of condition monitoring and protection devices in a single software solution. Eliminating the need for a PC or other software package, the data collector works in tandem with the System 1 Collector app that runs on an industrial smartphone or handheld tablet. Users can collect vibration data, take photos, send text messages, check email, make phone calls and run other applications, all on one device.
https://bently.com
Traditional methods of evaluating casing and tubular connection make-up graphs rely solely on training and operator experience. The Intelligent Connection Analyzed Make-up (iCAM) application removes human subjectivity by giving the operator a suggested connection disposition along with diagnosis and prescription of remedy if an anomaly occurs. iCAM is an automated connection integrity evaluation system that uses machine learning and big data analytics to “learn” from historical data and make recommendations to assure connection integrity. The iCAM application is designed to reduce personnel on board and reduce or eliminate the need for connection lay down and rework to achieve cost savings. The system provides an accurate, consistent and reliable evaluation of connection integrity.
www.franksinternational.com
OIL&GAS ENGINEERING DECEMBER 2019 • 17
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Advances in Flowmeter Proving for Shale Fields Brian Hoover | Business Development Manager, Endress+Hauser
The oil and gas production renaissance in the U.S. has resulted in a large number of allocation and custody transfer meter installations. These installations are driving an increased need for “proving” or calibrating flow measurement points used for transactional purposes. Meeting these calibration requirements in oil and gas fields is particularly difficult because shale plays are often in remote and isolated locations, far from proper maintenance facilities. Flowmeter proving must be conducted on a regular basis due to regulations, legal contracts and validating accurate internal transfer of product. EPA regulations on reclaimed water used in fracking also require frequent flowmeter testing.
Instead of relying on ball provers, piston provers or master meters, recent developments make it possible to bring a “calibration lab” to the shale field. For example, Endress+Hauser is working with a third party to deploy its HP80 (US patent pending 15/605,562) Field Reference Meter Standard for mass, density and volume determination under existing operating conditions. This solution is also being adopted for calibration of tanks and level instruments. This type of field reference meter standard system provides field metrologists and calibration specialists with the metrics, tools and information needed to measure and manage all primary measurements in the upstream, midstream and downstream segments of the oil and gas market, including shale fields.
This increased demand, coupled with a shortage of staff and systems, has created a “calibration crisis” in many shale fields. The solution to this problem lies with better methods for calibration. Rather than removing flowmeters for shipment to calibration labs, recent developments—now being deployed in the Permian Basin—bring flowmeter calibration to the shale fields.
A typical calibration takes 30-45 minutes per meter including connection, test report generation and disconnection time. Field trials have shown these types of field reference meter standard systems can calibrate two to four times faster than a conventional ball or piston prover, with much greater accuracy on a mass basis. Download the paper at: https://bit.ly/2Kzc35x
brian.hoover@endress.com • www.us.endress.com
CYBERSECURITY
An immutable ledger enables multi-party operations Put settlement disputes to bed and ensure multiparty accountability By Norman Thorlakson
Figure 1: A layered and decentralized cybersecurity enforcement approach is universally applicable across different assets installed at the edge. Image courtesy: Xage Security
T
he age of digitalization promises accuracy, speed and safety, but to harness these benefits, it is imperative that oil & gas operations implement comprehensive cybersecurity solutions that are legacy-device compatible, scalable, and capable of enforcing roles-based access control policies (RBAC) and multi-party trust. Oil & gas operations are often spread out geographically and in remote locations –– leaving digital assets to the mercy of the elements, and reliant on the accuracy of operators to calibrate devices, update firmware and maintain accurate records of meter readings (particularly during custody transfer). With many processes dependent on manual input — and using a single password across personnel — transparency and accountability can disappear, resulting in financial loss, settlement disputes and even physical danger that can arise from operations malfunctions. What’s more, the energy industry is a target for cybercriminals who focus on industrial IT/ OT disruption, including competitive and rogue nations going after rival states, and organized criminals hoping to extract ransomware payments. A variety of threats, including phishing, malware infected devices inside the firewall, and even disgruntled employees, can initiate attacks that result in damage and halts in operation. These threats must be met with comprehensive cybersecurity capable of detecting, identifying and blocking such events, to prevent financial, physical, legal, and business impacts. Risks to operations Oil & gas organizations employ a unique operational architec-
ture, and one that is as complex as it is interdependent. Characteristically, this architecture is decentralized — by the sheer quantity and location of geographically disparate devices — and diverse, with assets that span different generations, vendors, types, makes, models, and connectivity means (wired, wireless, serial, RF). As operations continue to digitalize, it is common for legacy and next-generation technology to work together — exchanging data across channels, under the same firewall and within adjacent domains. These devices require access from various personnel to calibrate systems, deliver maintenance and record data. These devices, once isolated but now connected, present vulnerabilities and entry points for malicious actors seeking access to oil & gas operations. In an ecosystem where so many different components (data, applications, devices and people) play a role in day-to-day functionality, control is essential. A security system that allows organizations to log all interactions or changes made by internal personnel, block unauthorized access attempts, and tamperproof devices across an ecosystem, creates an invaluable blanket of trust across the entire operation, and between multiple parties in the supply chain. For example, on a pipeline, commodities are exchanged between supply chain partners that rely on accurate meter reporting. These devices are in near constant use and left out in the field where they are exposed to harsh conditions — requiring frequent recalibration. As a result, it is not uncommon for personnel to override faulty meters and adjust numbers based on assumptions or historical estimations. When this occurs, however, financial settlements can be thrown into question when records undergo an audit. Unverified recording can result in settlement disputes and inaccurate product volumes. A second example is the refinery, where inputs like feedstocks, electricity from the local OIL&GAS ENGINEERING DECEMBER 2019 • 19
CYBERSECURITY
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utility and other raw materials are consumed daily. To minimize external operations, refineries will track feedstocks and record meter readings on devices susceptible to inaccurate reporting. These meters are often physically and digitally exposed, lack adequate cybersecurity and require manual record keeping. If a valve is left open, stock records may not account for the isolated loss. If an oil tanker makes a delivery and a receiver is not onsite, there is no cross-check of the shipment details. Mistakes are made, devices are faulty, or people file false paperwork –– so much so that some multinational corporations admit up to 3% of production is lost and unaccounted for as a result of discrepancies during custody transfer. When this happens, the integrity of the delivery record can be put into question, and settlement disputes between supply chain partners can ensue. Guaranteed integrity To put settlement disputes to bed and ensure multiparty accountability, oil & gas operations need to employ comprehensive cybersecurity solutions and strategies that guarantee integrity and clarity across operations. One way to establish accountability and trust is using an immutable ledger, i.e., a record that cannot be changed. The ability to accurately and definitively record all transactions, adjustments, and access attempts across systems eliminates uncertainty in the case of any supply chain transaction, modification, or (at worst) cyberattack. It is essential that cybersecurity solutions guarantee an immutable ledger to avoid questionable devices, such as meters. Distributed cybersecurity approaches, often underpinned by decentralized blockchain technology, copy records across devices (nodes), creating an irrefutable account of all access, readings and modifications. In the case of a compromised meter or an unauthorized attempt to change a meter reading, the consensus-based blockchain is self-healing: using the immutable ledger to automatically correct any changes made to the record from a rogue device or user. Further, if a device is compromised, the system isolates that device to prevent system-wide interruptions — another critical capability. This process of automatic synchronization and consistency across assets should be the 20 • DECEMBER 2019 OIL&GAS ENGINEERING
standard in an industry where marginal errors can result in hefty losses. With an immutable ledger, operational records and the devices they originate from are given integrity and provide immutable records — from wellhead to pipeline operator and/or refinery and beyond. Decentralized enforcement strategy A decentralized cybersecurity enforcement approach also offers oil & gas organizations the ability to scale without the increased cybersecurity risk, as is the case with a traditional centralized cybersecurity architecture. The immutable ledger logs all transactions, events, and logins, then automatically copies recorded data across system nodes. Because the cybersecurity system is based on consensus, the addition of assets creates a stronger record and voting system with each device added to the network — in direct opposition to a centralized approach that becomes more vulnerable with more points of entry. Why this, and why now? Decentralized cybersecurity enforcement, based on policies that can be defined centrally and automatically replicated to every corner of the operation, is the best fit for new industry challenges related to oil & gas digitalization. Although the increase and expansion of connected digital operations promises accuracy, speed, and safety, it also opens oil & gas operations to new deployment obstacles and vulnerabilities. In the face of these potential risks, an immutable distributed ledger provides a comprehensive foundation and solution for IT/OT cybersecurity challenges. It offers an irrefutable record that preserves data integrity, enforces RBAC, and safeguards the larger ecosystem for multiparty collaboration and transactions across the supply chain. This spares companies time and money from audits, reporting disputes, operational disruption, trade settlements, compromise of confidential operational data, and any inconsistencies that may otherwise impact the bottom line. The immutable ledger offers a unique solution and gives oil & gas operations the opportunity to reap the benefits of digital transformation to the fullest. OG Norman Thorlakson is vice president of business development, Xage Security.
Warning! Analog telephone circuits are being discontinued! What are your options? Summary: As telephone companies discontinue support or even disconnect analog telephone circuits, critical industries that have used these circuits for transmitting mission critical data are facing some formidable challenges. Many of these circuits are in rural locations where it is cost prohibitive for telephone companies to build ďŹ ber circuits or replacement of the circuits are not in the telephone companies’ business plan.
Challenge: Telephone companies are discontinuing support or disconnecting analog phone circuits which have been used by oil and gas companies for data transfer for many years. In many cases, they are not offering a replacement solution.
Solution: Private, licensed wireless radios can replace these analog phone circuits. Wireless technology has improved in the past few years and can have very low latencies providing a solution for many Supervisory Control and Data Acquisition (SCADA) circuits including some transfer trip applications.
Result: Implementing wireless solutions before a phone company discontinues support of these circuits can minimize or eliminate downtime for critical data.
For many oil and gas companies, this creates a great challenge as they need the circuits to send critical information or even controls, but there is no longer a wired solution. In the past, many wireless solutions had higher latency than could be tolerated by some control applications. As wireless technology has progressed, wireless solutions are approaching lower latencies and in some cases, private, licensed wireless networks or point to point links can replace these antiquated telephone leased circuits. In cases of control circuits or mission critical data, it is important to look for a private, licensed wireless solution as public wireless carriers do not typically have the availability, reliability, security, and low latency these circuits require. Unlicensed wireless alternatives are susceptible to interference and may also not meet latency requirements. By working with manufacturers that provide private, licensed wireless solutions and not waiting until analog leased circuits fails, oil and gas companies can ensure their critical control and data is not compromised.
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TAKING IT TO THE EXTREME
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• • • •
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