OGE_19_10 by Modiconlv

WELDBEND.COM

COMMENT

3010 HIGHLAND PARKWAY, STE. 325 DOWNERS GROVE, IL 60515 630-571-4070, FAX 630-214-4504

CONTENT SPECIALISTS/EDITORIAL KEVIN PARKER, Editor 630-890-9682, KParker@CFEMedia.com KATIE SPAIN, Art Director KSpain@CFEMedia.com

PUBLICATION SERVICES JIM LANGHENRY, Co-Founder & Publisher JLanghenry@CFEMedia.com STEVE ROURKE, Co-Founder SRourke@CFEMedia.com AMANDA PELLICCIONE, Director of Research APelliccione@CFEMedia.com KRISTEN NIMMO, Marketing Manager KNimmo@CFEMedia.com PAUL BROUCH, Director of Operations PBrouch@CFEMedia.com CHRIS VAVRA, Production Editor CVavra@CFEMedia.com MICHAEL ROTZ, Print Production Manager 717-766-0211, Fax: 717-506-7238 mike.rotz@frycomm.com MARIA BARTELL, Account Director, Infogroup Targeting Solutions 847-378-2275, maria.bartell@infogroup.com RICK ELLIS, Oil & Gas Engineering Project Manager, Audience Management Director 303-246-1250, REllis@CFEMedia.com LETTERS TO THE EDITOR Please e-mail your opinions to KParker@CFEMedia.com INFORMATION For a Media Kit or Editorial Calendar, e-mail Susie Bak at SBak@CFEMedia.com REPRINTS For custom reprints or electronic usage, contact: Marcia Brewer, Wright’s Media 281-419-5725, MBrewer@wrightsmedia.com MAILING ADDRESS CHANGES Please e-mail your changes to customerservice@CFEMedia.com

PUBLICATION SALES JUDY PINSEL, National Sales 3010 Highland Parkway, Ste. 325 Downers Grove, IL 60515

JPinsel@CFEMedia.com 847-624-8418 Fax 630-214-4504

Rotating equipment makes the world go ‘round

“W

hat you have to realize is that the midstream is all about rotating equipment,” said Craig Harclerode, industry principal, oil & gas, with data infrastructure and historian supplier, OSIsoft. Armed with this interview-derived insight from a manager at one of the seminal technology innovators of our time, anyone would have been well-equipped to hear of the high-tech turn taken at the Turbomachinery & Pump Symposium, held September 15 – 17 in Houston. A case in point is the announcement made by Bently Nevada, a business of Baker Hughes, the provider of integrated oilfield products, services and digital solutions. Bently products monitor the mechanical condition of rotating equipment found in machinery-intensive industries. Sixty years ago, Don Bently invented the eddy current proximity probe, the first sensor that measured vibration in high-speed turbo machinery by allowing direct observation of the rotating shaft.

Into a wider world At the symposium, Bently introduced its response to the latest advances in IT-based industrial computing, aka, the industrial internet of things. “The engineering team is excited about the first major update of this important product line in 20 years,” said Terry J. Knight, president and CEO of Bently Nevada and the measurements and controls business of Baker Hughes. The Orbit 60 series is an update of the 3500 machinery protection system, which is said to have 85,000 racks installed worldwide, 60,00 of them in oil & gas. The Orbit 60 series collects and processes data, equipping operators with the data and analytics to determine machine health. When the 3500 was developed there was no concern with cybersecurity, said Knight. The Orbit 60 includes the latest connectivity capabilities but the separation

2 • OCTOBER 2019 OIL&GAS ENGINEERING

KEVIN PARKER EDITOR

of protection from condition monitoring precludes anyone preempting the equipment’s control. Moreover, the system has 100x higher signal processing power than the industry standard. A built-in diode enables data transfer from the device to Bently Nevada’s machinery management software System 1 for proactive monitoring and diagnostics. Edge trends “This is an edge device. The primary connection is to System 1, but users can do their own analytics, some on the edge, some going to the cloud for fleetwide analyses, if desired. The gateway allows inclusion of process data. What’s most important is that access to data opens up a wider world,” said Steven Sturm, senior product line leader. Rotating equipment providers and users are always looking for new measurements. “The device is built for flexibility because we’re not certain what the basis for measurement will be,” said Sturm. While machine learning can be used to mimic the intuitive insight humans use to analyze situations, e.g., “That just doesn’t sound right,” one distinction between machine learning and physics-based analysis, Sturm said, is that physics-based analysis more easily lends itself to root-cause analysis. More generally, it’s clear that, like Bently Nevada, a wide range of oil & gas equipment and machine providers are releasing their own responses to the introduction of IIoT and the impending age of analytics. For more on rotating equipment in the oil & gas industry, see Harclerode’s byline in this issue, “Midstream’s dilemma with rotating equipment.” OG

I NSIDE

Cover photo courtesy: Twin Disc Inc. 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.

FEATURES 4

API 18.2 recommendations improve level instrumentation Updates to safety standards call for capable instrumentation to address safety and accuracy concerns

Active analytics can drive better business decisions

With a GPU-accelerated database, organizations evaluate larger data sets

Rail-supplied midstream propane terminal optimized for safety

Tterminals make delivery process cost-effective for local and regional propane providers

Midstreamâ&#x20AC;&#x2122;s dilemma with rotating equipment Decision support platform captures real-time data and delivers operational intelligence

OIL&GAS ENGINEERING OCTOBER 2019 â&#x20AC;˘ 3

CUSTODY TRANSFER

API 18.2 recommendations improve level instrumentation Updates to safety standards call for capable instrumentation to address safety and accuracy concerns By Lydia Miller

Figure 1: Guided wave radar level gauges are a technology able to detect and measure an oil-water interface position. All figures courtesy: Emerson Automation Solutions

ituations where money and merchandise change hands between two parties are often regulated by a third party to make sure the transaction is accurately made and recorded. When crude oil is purchased by a refiner or pipeline company, the custody transfer at the wellhead is regulated by the American Petroleum Institute’s API MPMS, Chapter 18.2 standard to ensure both parties understand and accept the transaction. Prior to 2016, the methods for measuring and evaluating oil during custody transfer from a wellhead site were described in API MPMS, Chapter 18.1: Measurement Procedures for Crude Oil Gathered from Lease Tanks by Truck. This standard was published in 1990 and became widely recognized as the accepted method for this type of custody transfer. API MPMS, Chapter 18.1 was updated over the years before being supplanted in 2016 by API MPMS, Chapter 18.2: Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods, which is now the recognized standard and offers significant advances over its predecessor. At the time of its release, API issued this explanation: “Industry standards developed by API support the industry goal of zero accidents,” said Lisa Salley, API’s vice president for global industry services. “This standard is a great example of what can be done when industry, regulators and all key stakeholders work together to achieve the common goal of improving safety for industry operations. This standard

4 • OCTOBER 2019 OIL&GAS ENGINEERING

enables personnel to take measurements of crude oil from a lease tank without opening the hatch on the tank, thus protecting them from potentially hazardous vapors and gases.” The new standard still allows for the old practices to be retained, but it offers mechanisms to use methods better able to make oil volume measurements more accurate, and the process of transferring oil much safer. The old-fashioned method Under API MPMS, Chapter 18.1, large production sites with frequent deliveries could be outfitted with a lease automatic custody transfer (LACT) skid. A LACT uses a sophisticated flowmeter to measure the volume of oil transferred along with other parameters, such as density, but it is not economical for smaller sites and volumes. The manual practices under API MPMS, Chapter 18.1, were designed to work anywhere, including wellhead sites that had effectively zero instrumentation. All the measurement methods could be carried out by a receiving truck driver using a kit of simple manual tools to take readings from the top of the tank. Here are the steps:

The truck driver climbs to the top of the tank, opens a thief hatch and lowers a tape measure with a float to determine the oil level. This first measurement is called the opening gauge and establishes the baseline measurement.

2. The next step is to lower a thermometer or temperature sensor to read the oil temperature, which is used to support a density calculation. Depending on the oil depth, up to three readings should be taken at three depths due to potential temperature

stratification. The density calculation uses an average of the three readings.

3. A collector is dropped in to capture a sample. Specific gravity can be measured using a hydrometer corrected by the temperature. Some of the sample goes into a centrifuge for the “grind out” to determine how much water and solid material is mixed in. The measurements from a single sample are applied to the entire lot.

4. If the driver is satisfied with the quality, the oil can be pumped into the truck. When the transfer is over, the driver takes a second level measurement (closing gauge) with the tape to calculate the volume transferred based on the tank’s dimensions. All the necessary equipment was carried from site to site and nothing was automated. Everything had to be written down or manually entered into a computer. The ability to measure accurately was utterly dependent on each driver’s skill and finesse with the tape measure, which introduced significant variability. The U.S. Bureau of Land Management reported that typical manual tank gauging uncertainties range from 0.6% to 2.5%. Using a midpoint of 1.5% uncertainty and applying that to a well producing 600 barrels per day of oil at a sale price of $55 per barrel, this could result in an annual discrepancy of $180,000. Another potential problem area is water accumulation in the storage tank. If the production separator is not working correctly or experiences an upset, water can be diverted to the oil tank or vice versa. If this problem is not detected, oil in the water tank will be sent out with the water hauler. If the oil-collecting driver doesn’t realize what has happened, water can be transferred along with oil. A manual level measurement from the tank roof using a tape cannot determine where an oilwater interface is in the tank. The most dangerous aspect of the process is what can happen to the driver when opening the thief hatch. There is no specific number on how many drivers were greeted by an unwelcome blast of hydrocarbon fumes

or toxic hydrogen sulfide expelled from the tank. The fortunate ones probably only suffered dizziness, fainting, headaches or nausea. Others weren’t so lucky. Between 2010 and 2014 the National Institute for Occupational Safety and Health identified nine fatalities of workers overcome during manual tank gauging and sampling operations. As mentioned earlier, this heart-breaking fact was one of the key drivers in the development of API MPMS, Chapter 18.2. Using alternative methods The new measurement methods in API MPMS, Chapter 18.2, include the ability to perform many of the relevant transfer measurements in either the trailer or truck zone or the transition zone rather than making them all in the tank zone. This allows the measurement taker to remain on the ground and away from many of the harmful vapors. The temperature can be monitored continuously during the transfer, and samples for “grinding” and density evaluation can be taken at any time from the pipe carrying the oil from tank to truck. Volume transferred can be measured in one of two ways. First, a flowmeter can be used without the need for implementing a full LACT skid. API MPMS has chapters covering a variety of flowmeter technologies used for this purpose. Second, the opening and closing gauge measurements are still used, but with the measurement performed using a level instrument rather than manual measurement. Choosing the most suitable level instrument becomes a critical question. The application calls for several key capabilities: • A high-precision, fine-resolution continuous measurement from the top down • A simple mechanism requiring minimal maintenance • An ability to detect and locate an oil-water interface. Meeting these three requirements with one technology narrows the field quickly: Radar instruments that mount from the top not only minimize the need for mechanical modifications to a tank, but they also have no moving parts. OIL&GAS ENGINEERING OCTOBER 2019 • 5

CUSTODY TRANSFER

Figure 2: WirelessHART instrumentation allows users to avoid the high cost of adding wired infrastructure at well sites.

This approach is ideal since it provides the precision and resolution needed. API MPMS, Chapter 18.1, called for three consecutive manual readings to agree within 0.25 inches. The right radar level gauge can provide reliable readings with accuracy better than 0.125 inches, meeting the first and second requirements. The third requirement is the most difficult to meet, as few technologies other than guidedwave radar (GWR) (Figure 1) are capable of detecting and measuring the position of an oil-water interface. Magnetostrictive level instruments can be set up to capture an interface measurement, but effective operation depends on consistent densities of the liquids and free movement of the floats. If tar or other material from the oil accumulates on the rod it can interfere with movement, and the reliability of a reading will be lost. There is no way to tell this is happening from the reading data, short of the float freezing in one position. A GWR probe can also accumulate buildup, but it takes a lot of material to interfere with the reading. Moreover, the nature of the echo curve can be monitored to indicate if material is building up, allowing appropriate maintenance action to be taken. Additionally, if there is an emulsion layer between the two liquid layers instead of a definite interface, the magnetostrictive device will always float at a point in the emulsion layer. If an operator relies on that measurement for the separation, some of the material identified as oil will be an emulsion of oil and water. Radar, on the other hand, will not measure well with an emulsion, indicating that separation is not complete.

6 â&#x20AC;˘ OCTOBER 2019 OIL&GAS ENGINEERING

Automated data collection Absent a situation where a LACT skid is available, the manual actions of custody transfer under API MPMS, Chapter 18.1, did not lend themselves to automated data collection. Accurate record keeping depended on the fastidiousness of the driver either writing down the figures legibly or entering them without error into a laptop or tablet. API MPMS, Chapter 18.2, was developed specifically to allow for replacement of many of the manual measurement methods with the additional allowance for measurements to be made outside the more dangerous tank zone. Using a GWR level gauge along with temperature transmitters and other electronic instrumentation provides the ability to tie readings directly to a data-gathering platform, greatly reducing the potential for errors. Additionally, the use of GWR for level measurement, instead of float-based technologies, can improve measurement reliability and help to monitor separation. The growing availability of WirelessHART instrumentation makes this easier to implement since these require no wired infrastructure for power or data transfer from the instruments. All the instruments necessary to perform a transfer operation under API MPMS, Chapter 18.2, are available as battery-operated wireless units, including GWR level gauges (Figure 2). Wired instruments are also available to perform all the necessary tasks. These elements, working together, can produce a higher level of accuracy and reliability while avoiding potentially lethal safety concerns. API MPMS, Chapter 18.2, shows how users can put these techniques to work to produce the desired results in a safe and repeatable manner with reduced requirements for onsite labor. OG Lydia Miller is a product manager with Emerson Automation Solutions, working with Rosemount level products, with a focus on radar and ultrasonic instruments and level switches. She joined the company in 2011 and has additional work experience with air-to-air energy recovery for process industries and HVAC applications. Lydia has a bachelorâ&#x20AC;&#x2122;s degree in mechanical engineering and English from the University of Minnesota.

What do you get when you pair the industry’s leading edge connectivity & computing platform with ċĚƙƥȹĿŠȹČŕîƙƙ q£¹¹ȹĚŠîċŕĚē ĚēĳĚ ƙūĲƥǅîƑĚȧ

NEW ABILITY TO TRANSFORM

With FreeWave’s ZumLink™ and IQ running AUTOSOL’s eACM software, you can convert RTU and PLC protocols to MQTT, the leading protocol for IIoT—to get more data from the ǛĚŕē ĲūƑ ċĚƥƥĚƑ ēĚČĿƙĿūŠ ŞîŒĿŠĳȦ

Attend FreeWave and AUTOSOL’s joint webinar “SCADA Application Optimization: Rugged Reliability and Real-Time MQTT” on October 10 to learn more. Register today at freewave.com/mqtt

STRESS.

MANAGEMENT.

Continental Extended Life™ Constant Pressure Hose gives you peace of mind. With its unparalleled flexibility in tight situations, reliability in extreme environments and a bite-to-wire coupling that hangs on no matter what, this is one hydraulic hose that won’t let you down when the pressure’s on. After all, you have enough to chew on. All you’re asking for is a fitting that won’t let go and a hose that won’t let you down. Continental. We Have an Answer for That. WeHaveAnAnswerForThat.com

THE AGE OF ANALYTICS

Active analytics can drive better business decisions With a GPU-accelerated database, organizations evaluate larger data sets By Nohyun Myung

Figure 1: With a GPU-accelerated database, organizations evaluate much larger data sets, 100 times faster than possible with CPU power alone, increasing performance capability and advanced geospatial analytics at scale. All graphics courtesy: Kinetica

il & gas companies rely on a variety of data sources to inform their business decisions. In today’s industrial environments, the data collected includes more real-time data sets, such as higher velocity streaming drilling information. When it comes to the modeling of basins, geophysicists, petro physicists and geologists all contribute to the collection of this vast data set. Because they require a certain degree of confidence that the locations chosen for drilling will generate substantial extraction of energy resources, many organizations want to accurately model subsurface reservoirs before beginning any actual well drilling or development. From a data perspective, the more models generated and the more granular they are, the better and more profitable the decisions taken by the company. However, generating granular models requires a massive amount of data — currently a major challenge for these organizations, as they are ill-equipped to process and analyze data at scale. GPU-enabled acceleration Oil & gas companies operate like any other enterprise: they tend to store all the data generated across the organization — from well sensors to drilling information — in traditional data lakes within an enterprise data warehouse, like Hadoop, HDFS or Cassandra, or across distributed database systems. While some companies are migrating to cloud warehouses, like Snowflake, or static formats, including Azure Blob Storage or Google Cloud

10 • OCTOBER 2019 OIL&GAS ENGINEERING

Storage, the challenges remain the same – these methods were primarily developed for storing data. As a result, they are unable to process the data collected, creating bottlenecks and inefficiencies for organizations. This slows down the well-vetting process and, ultimately, resource extraction. This is where a graphics processing unit (GPU)-accelerated database, like the Kinetica Active Analytics Platform, comes into play. With a GPU-accelerated database, organizations evaluate much larger data sets, 100 times faster than possible with CPU power alone, increasing performance capability and advanced geospatial analytics at scale. Returning to the basin modeling example, most systems traditionally used to analyze subsurface modeling include only five to ten million records for a subsurface reservoir basin, offering limited granularity and a passable level of confidence about the basin. When leveraging a GPU-accelerated database for basin modeling, companies get an MRI-like image of the earth subsurface, visualizing 100 billion data points instantaneously, for a higher level of granularity and confidence. The more granular the information used to build a model, the more accurate it will be – leading to a better assessment of the basin properties being explored. Building the model is just the first step. For oil & gas companies to gain valuable insights from the data, the analytics platform will need to dynamically slice and dice and filter that data. It’s one thing to have the data, but without being able to read the data effectively and accurately, the model will fall flat. Companies need to quickly analyze, filter and sort data to fit the attributes optimal for resource extraction. With a GPU-accelerated database, companies home in on what properties to focus on within the larger datasets. Let’s say you are examining a basin model, filtering the properties ideal for deciding well

placements, and something interesting is identified on the basin’s west side. By being able to filter the sought-for properties, natural resources will be extracted in a much more responsible, safe and efficient manner, giving engineers information about the best location to drill the wells with minimal effort. Steps to a data analytics solution For oil & gas companies to take full advantage of a data analytics solution, a couple of steps are mandatory. First, because these organizations typically get information from a wide variety of sources, they must standardize their data sets. Data analysts receive models in anywhere between five and fifteen different formats, which can vary greatly in terms of quality, density and source. To gain the best insights, organizations must create a truly authoritative and standardized system of record for whatever data they are collecting and storing, whether it be basin models, well data, or any other type of data they collect. Second, organizations must create a standard around the different properties known to be relevant for a particular basin. Having a standardized catalog across all data sets is critical. Take the Delaware Basin or the Permian Basin in Texas – what are the specific characteristics of the reservoir that can provide concrete clues as to where to place a well in order to do exploration? Third, after standardizing and setting properties, analysts must think about how to represent and use the data. Users must be able to effectively interact with the data to derive decisions that help the business. Questions to think about include what the front end is going to look like and what tools analysts will use to deliver the best, readily accessible information to the petro physicists and geophysicists, so that they can analyze and extract information with relative ease, arrive at results that maximize business impact. Infrastructure required To deploy an effective data analytics and datadriven solution, oil & gas organizations need a GPU-powered platform. Organizations leveraging GPUs take advantage of the computing power and low-latency performance to analyze vast swaths of data.

Another aspect of a good solution involves having efficient, lightweight, and clean user-interface and user-exploration tools that give end users (in the modeling example, geophysicists and petro physicists) the power to make good decisions about where organizations are going to spend millions or even billions of dollars to build out assets, purchase land, build wells, and establish the human infrastructure and human resources needed to propel hydrocarbon extraction. Establishing an effective data streaming pipeline is also key, whether it is static data cuulled from multiple sources, real-time drilling data or streaming data coming directly from the field via connected Internet of Things (IoT) devices. Anadarko case study Anadarko, one of the world’s largest oil and natural gas exploration and production companies, leveraged a GPU-based analytics platform that combines a GPU-accelerated database, streaming analytics, location intelligence, machine learning-powered analytics, smart applications, and cloud-ready architecture. To get started, Anadarko partnered with Kinetica to customize the platform to its needs. Kinetica then leveraged Google Cloud Platform (GCP) as a virtual infrastructure to be able to stand up to a fifteen-node Kinetica environment on GCP that’s using GPUs, and leveraging Google Cloud Storage as the static persistence of Anadarko’s data sets, whether models, wells, or any other data types the company may leverage. In this case, Google Cloud Storage is acting as the authoritative data source. From the Kinetica side, the team is leveraging its 15-node connected cluster to quickly and

Figure 2: When leveraging a GPU-accelerated database for basin modeling, companies get an MRI-like image of the earth subsurface, visualizing 100 billion data points instantaneously, for a higher level of granularity and confidence.

Figure 3: The more granular the information used to build a model, the more accurate it will be, leading to a better assessment of the basin properties being explored.

OIL&GAS ENGINEERING OCTOBER 2019 • 11

THE AGE OF ANALYTICS

Mr. Shims

your answer to better alignment for rotating machinery

1-800-72-SHIMS (1-800-727-4467)

www.mrshims.com

rapidly ingest data from Google Cloud Storage into the Kinetica platform, especially as data changes become rapidly available. Use of the platform and GPUs accelerates the output of Anadarko’s data scientists and geophysicists, as they run GPUaccelerated models that make faster spatial and economic predictions. This allows the geologists and petro physicists to do their analysis on the incredibly dense datasets in the most effective manner, identifying where and how to extract the resources from the reservoirs in the most cost-efficient, timeefficient, safe and responsible manner. With the Kinetica Active Analytics Platform, Anadarko did the impossible – render a high-fidelity, 3D view of the Delaware oil basin using 90-billion data points at scale. To put this into perspective, Anadarko moved from a low-fidelity (approximately nine billion data points) view of the basin, with the visualization equivalent to the size of Harvard University (approx. 20 acres), to a high-fidelity view (approximately 90-billion data points) that is Figure 4: With a GPU-accelerated database, orgaequivalent to the size of the nizations evaluate much larger data sets, 100 times state of Massachusetts and faster than possible with CPU power alone, increasthree times the depth of ing performance capability and advanced geospatial the Empire State Building. analytics at scale. End users get the most granular view at the basin, to make the best possible decisions. The end users, geologists and petro Belt/Sheave physicists are responsible for delivering Laser Alignment System recommendations to the business, used New Green laser delivers these important benefits: to decide whether, when and where to ● Reduces Vibration ● Eliminates downtime and productions purchase land to set up operations, build ● At an affordable price wells and so forth. For a company like ● Visible indoors and Outdoors ● Brightness great for long distances Anadarko, being the first company to act on where to purchase or lease land is 12 • OCTOBER 2019 OIL&GAS ENGINEERING

significant. It is typically a 500x to 700x cost difference between being the first company to purchase or lease land – especially when we’re talking about hundreds of thousands of acres at a time – and the second. That is, once it’s known that an organization is buying up land, all the other oil & gas companies jump on it as well. Innovation in IoT and edge The Internet of Things (IoT) and edge computing have accelerated innovations in the oil & gas industry, especially for companies that are data driven. With IoT and edge computing, companies establish real-time well monitoring, uncover drilling information, or vet expensive equipment. For example, IoT-enabled sensors can capture information on equipment conditions, which then is fed into a data storage solution and analytics platform, which is analyzed at the edge on the equipment itself, instead of being sent to a centralized data warehouse. This allows data analysts as well as end users to receive the data in real time, enabling companies to predict equipment failures before they happen, to minimize downtime. With these predictions, the companies can identify when preventative maintenance is needed, ahead of the issue occurring, avoiding very costly repairs and maintenance expenditures. IoT and edge computing also enable realtime streaming of drilling information, where companies can be informed almost immediately when they’ve broken into a different type of soil, based on the geologic time-series data about how far they are digging. Being able to identify that information and report on it is significant in terms of understanding how far the drilling team has gotten in the extraction operation. Technologies like active analytics, IoT, and edge computing have allowed oil & gas companies to effectively make better decisions for their businesses, from figuring out where to build wells to monitoring and predicting expensive equipment failure. In order to stay competitive, these companies must realize, and ultimately leverage, the most important asset they have: their data. OG Nohyun Myung is global director of emerging analytics, Kinetica.

MIDSTREAM OPERATIONS

Rail-supplied midstream propane terminal optimized for safety Terminals make delivery process cost-effective for local and regional providers By Crystelle Markley

Figure 1: The National Fire Protection Association NFPA 58 code regulates container spacing for railcar-supplied midstream propane terminals. A maximum of six storage containers can be located in a group, regardless of size, and requires 50 feet of separation between groupings. All figures courtesy: Superior Energy Systems

he role of rail in propane midstream operations is both substantial and crucial. Rail is key to getting propane to where it is needed, especially when customers are not close to a propane pipeline. Rail keeps costs stable because rail-supplied propane terminals preclude the use of trucks to transport propane great distances to rural areas, where the fuel is used for home heating and agriculture, among other uses. In a rail-supplied propane terminal, product that is primarily sourced from shale plays like Marcellus, Permian, Eagle Ford and others is offloaded from railcars using compressors, stored and then loaded via pumps into trucks that transport the product to bulk plants, which in turn load local transport vehicles like bobtails. Safety, of course, is the most important consideration in building a rail-supplied propane terminal, which means itâ&#x20AC;&#x2122;s important to work with a terminal supplier that is an expert in national and local codes and regulations. Overall design and storage need to be addressed first when building a rail-based midstream propane terminal operation. Distances

and aggregate storage capacities (i.e., total storage available) can place limits on storage and rail capabilities. It is also critical to assess necessary storage required to meet regional peak demand. The midstream supplier assesses past purchases, logistics associated with moving fuel from nearby refineries, and geographic needs based on historical data and supply and demand. The National Fire Protection Association NFPA 58 code regulates container spacing. A maximum of six storage containers can be located in a group, regardless of size, and requires 50 feet of separation between groupings. Rail switches The most critical part of building an advanced rail-supplied midstream propane terminal lies in efficiency of both rail switches and the unloading of propane tank railcars. Responsibility for the rail switch falls on either the midstream marketer/terminal owner or the railroad operator. When a rail terminal is built, many logistical motions come into play related to the movement or addition of track, the amount of railcar storage and the necessity of separate (on- or off-site) railcar storage locations. The addition of rail siding is necessary to offload railcars from the main rail line. Average railcars range from approximately 55 to 70 feet in length with a turning radius of approximately 240 feet. Engineering software programs allow terminal builders to determine the amount of land and length of rail siding required to meet the switch demand. (See Figure 1.) The switch demand, therefore, determines the number of gallons the midstream supplier will be able to move out of the terminal in a 24-hour period. Railcar unloading The efficient unloading of tank railcars affects the entire terminal operation, determining the speed that gas is unloaded and subsequently, the number of tanker trucks OIL&GAS ENGINEERING OCTOBER 2019 â&#x20AC;˘ 13

MIDSTREAM OPERATIONS

Figure 2: Railcar-supplied midstream propane terminals allow transport trucks to drive shorter distances for fuel deliveries to local propane providers. This makes the delivery process more cost-effective for those local and regional propane providers.

that can be loaded in a given amount of time. Amount of land space determines the installation of single- or doublesided rail towers. Double-sided rail towers are much more efficient, allowing unloading personnel to unload two cars without walking further down the railcar line. Double railcar siding requires more land space and the two rail lines must be separated by 21 feet, allowing the railcars to move with ease. If less land is available, single rail towers are placed along the siding, requiring personnel to travel to each tower to connect railcars to the liquid transfer system. Compressor size and unload pressures make a crucial difference in offload speed, as does the process used to remove the propane. Top connections are used to remove liquid propane, due to the nature of the fuel. Vapor removal and recovery is a significant detail that must be considered as well, in order to avoid losing potentially thousands of gallons of fuel over time. Truck transport loading Also important in rail terminal efficiency is the truck transport loading process. Land space determines the access road and driveway available to maneuver and stage transport trucks. (See Figure 2.) To meet high-performance requirements, terminal operations load trucks at a rate of 550 to 600 gallons per minute, allowing a transport truck to be filled in less than 15 minutes. At the truck loading rack, truck metering skids are calibrated to assure accurate custody transfer. Automation is also key. Billof-lading management, the programmable logic controller (PLC), tank-level system and terminal management software all come together to benefit both the marketer and the customer.

14 â&#x20AC;˘ OCTOBER 2019 OIL&GAS ENGINEERING

Permitting, safety and code compliance Permitting, code compliance and safety are key measures that must be considered in a railcar propane terminal build. Terminals must meet expectations and regulations set by NFPA 58, the local authority having jurisdiction (AHJ), and various local and regional entities, including the fire department, city and zoning departments. The following aspects help ensure a safe and compliant operation: OSHA rail guards: Permanent handrails must be installed alongside the rail towers and stairs. Removable safety rails are designed in a hoop-like shape to move up and down with the catwalk, providing the OSHA-required 42-inch fall protection. Shutdown devices: Operator devices must be installed per NFPA 58 in convenient locations at each rail tower and enable operators to open and close the liquid and vapor connections to each rail car. In addition, one emergency shutdown device is installed 20 to 100 feet from the point of transfer, which can be used to close connections to the entire rail rack. Hydrocarbon leak detection: Detection mechanisms should be installed around points of transfer and pumping systems (vapor compressors and liquid pumps) to detect propane leaks. When detected, the leak is reported to the PLC, enabling the emergency shutdown device and closing all valves to contain the leak. Fire hydrant/monitor nozzles: A fixed nozzle or hydrant must be installed at ground level, around the tanks, to provide tank cooling in the event of fire. Nozzle installation reduces tank separation requirements set by NFPA 58, allowing additional tanks to be installed in closer proximity. Backflow check valves: These are safety valves that allow propane to flow into the piping system, but not back out. The valves are critical in case of hose separation or piping damage. Positive shutoff valves: Valves are installed throughout the terminal, allowing for convenient isolation of various portions of the system to allow for service, without having to evacuate the entire piping system. They also provide a redundant positive shutoff in conjunction with emergency shutoff valves.

Breakaway devices: These are installed at unloading stanchions to separate at a predictable point in the event of an accidental transport truck pull-away, preventing damage to the loading or unloading equipment and loss of product from the system. Hydrostatic relief valves: These are installed in the piping system at any point where propane has the potential to be isolated between two positive shutoff valves. This protects the piping system from excessive pressure due to liquid expansion from an ambient temperature increase. Fire safety analysis In addition to the measures previously noted, the terminal supplier develops a Fire Safety Analysis (FSA), required by NFPA 58. The main goal of NFPA 58 is to prevent any unintentional release of propane into the atmosphere. The FSA must be completed prior to terminal operation but is often required much earlier, during the permitting process. The FSA determines the safety of the terminal itself based on safety features required by NFPA and additional measures put into place to prevent propane release accidents. The FSA ensures the terminal will be built to and likely exceed customer requirements, along with meeting appropriate federal, state and local codes and standards, which require: • All container openings are properly equipped to meet the requirements that incorporate mechanical, thermal and remote means of operation, including activation and emergency shutdown as required by code. • Containers have the required liquid level devices, such as a float gauge, rotary gauge, slip tube gauge or a combination to prevent overfilling. • The presence of vapor pressure and temperature gauges. • Properly sized tank relief valves to protect the tank from overpressure. Terminal commissioning The terminal supplier will begin the commissioning process about two weeks before the project is completed, which includes testing the installation of every part of the system, per the design plan.

This rigorous evaluation process includes: • Performance and functionality testing of the compressors, pumps and motors • Pressure testing the piping system • Testing of the PLCs, the core of the terminal’s system • Testing of additional safety systems, including the hydrocarbon detectors, liquid level systems and emergency safety devices • Meter calibration. The terminal contractor then coordinates all inspection approvals to ensure compliance with each issued permit, including walk-throughs by the building, electrical and mechanical inspectors. Following full testing and inspection approvals, the terminal’s onsite operations personnel is trained. Local AHJ personnel is also trained on the terminal’s features and safety systems. The start-up and first product-transfer is often monitored by the terminal contractor as well as the operations team. Final words Railcar-supplied terminals are integral part of the midstream propane landscape, for the simple fact that they ensure propane gets to where it is needed. Terminals allow transport trucks to drive shorter distances for fuel deliveries to local propane providers. This makes the delivery process more cost-effective for those local and regional propane providers. Developing a rail-supplied midstream propane terminal is a complex process that requires a high level of design and engineering acumen to ensure a terminal is a safe place that meets requirements of national and local authorities as well as the AHJ. In other words, experience counts, and working with a provider that specializes in the nuance of terminal building can significantly increase savings in both capital and time. OG

Figure 3: Permitting, code compliance and safety are key measures that must be taken into account in a railcar propane terminal build. Terminals must meet expectations and regulations set by NFPA 58, the local authority having jurisdiction (AHJ), and various local and regional entities, including the fire department, city and zoning departments.

Crystelle Markley is Marketing Director at Superior Energy Systems, Ltd. OIL&GAS ENGINEERING OCTOBER 2019 • 15

FreeWave’s Edge Computing Platform Enables $15,000 in Manual Inspection Cost Savings with Remote Site Monitoring Summary: An independent petroleum and natural gas company was seeking a solution to remotely monitor its Accuflow water injection controllers at various well sites in the Southern California desert. Previously it had been deploying field personnel to manually record flow totals from each of the nearly 70 injectors daily.

Challenge: A Southern California petroleum and natural gas company sought a cost-saving solution to replace manual well pad inspections and proactively identify potential operational problems for one of its crucial well sites encompassing 70 active water injectors.

Solution: Deployment of 79 FreeWave ZumLink™ Z9-PE 900 MHz industrial radios with one IQenabled base station device running Node-RED to publish 24/7 real-time site data to the company’s email servers via Internet connectivity.

Result: Immediately reduced ﬁeld personnel deployments and truck roll costs for well pad inspections – representing $15,000 in manual inspection cost savings annually – reducing maintenance overhead while increasing worker safety and reporting accuracy.

Implementing FreeWave’s C1D2-certified ZumLink™ Z9-PE 900 MHz radios loaded with the IQ Application Environment, a Linux-based platform to host third party industrial applications, the company was able to run a Node-RED edge application to remotely access water injection data from any device in real time. The application extracts flow totals remotely over the Z9-PE radio links and automatically sends out a daily report email. In total, 79 ZumLink radios were deployed with the custom application hosted on a Z9-PE loaded with IQ at the base station. With real-time data access, the company was able to minimize truck rolls, improve worker safety, and enable predictive maintenance. As a result, the company saw immediate and significant reductions in insurance, fuel, and employee costs, estimating $15,000 annual savings in manual inspection costs. They are also able to gather data from multiple points at a higher frequency for more proactive monitoring of many well pad performance vectors, further optimizing site efficiencies. Read the full case study at: www.freewave.com/monitorsites.

info@freewave.com +1 866.923.6168 www.freewave.com

Visit www.controleng.com/stratusedge

The Edge Is Where The Action Is

today to download the trend report!

The introduction of edge computing is the most significant plant-floor advancement in industrial computing since the introduction of supervisory control and data acquisition (SCADA) 30 years ago. This next wave of digital transformation offers tremendous potential to those who respond early and capitalize on the improvements that can be brought to their operations.

Edge computing is the future. Download the trend report to see results of the recent CFE Media and Technology survey of its readership regarding opportunities, challenges and attitudes when it comes to living at the edge.