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4 • OCTOBER 2017
Keeping an industry above water
W
KEVIN PARKER
hen Hurricane Harvey slammed into Texas as a Category 4 hurricane, on the night of Friday, Aug. 25, it shut down 10 oil refineries that process up to 2.2 million barrels of crude oil per day into products like gasoline. Following other recent hurricanes, prices peaked within two weeks after landfall at a level of 20 cents to 80 cents per gallon higher, according to PIRA Energy, an analytics unit with S&P Global Platts. The United States is the world’s top oil and natural gas hydrocarbons producer. It has been the top producer of natural gas since 2009 and the top producer of petroleum hydrocarbons since 2013, the U.S. Energy Information Administration says. In fact, oil production in the U.S. doubled from 2008 to 2016. This rapid capacity expansion goes a long way in explaining Harvey’s muted impact on gasoline prices, as it has been possible to redirect gasoline exports to American markets, according to The Christian Science Monitor. This is true even though, while the U.S. has the world’s largest refining capacity, just under half of this capacity is concentrated in Texas and Louisiana.
produced in the Gulf of Mexico was shut down. Oil producers in the Eagle Ford Shale region halted some operations. In the wake of the storm, gas futures jumped as much as 7%. Partly due to a lack of supply from refineries, major regional pipelines such as the Magellan shut down while the Colonial and Explorer pipelines operated at reduced rate, reported OilPrice.com. Despite the disruptions constraining flows of resources across the United States that led to a surge in oil and gasoline prices, the latter have already begun to stabilize. Harvey had limited impact on natural gas markets. Experts say prices have increased only 4%. This explains why the Gulf of Mexico’s share in American gas production fell from 25% to 5% as shale gas production has shifted to other parts of Texas and to the Appalachian Basin in the Northeast, according to OilPrice.com.
Changed landscape In fact, about one-third of the country’s refining capacity is located between Lake Charles, La., and Corpus Christi, Texas. The Houston area is home to refineries that include the Marathon Galveston Bay, Phillips 66 Sweeny, Exxon Beaumont, LoyondellBasell, and Motiva. Many have reported reduced capacity following the hurricane. Harvey caused about 25% of the country’s refining capacity to shut down. On the production side, by Aug. 27, according to the Interior Department’s Bureau of Safety and Environmental Enforcement, about 22% of the oil
Flotsam and jetsam From Aug. 23 to 30, 46 facilities in 13 Texas counties reported an estimated 4.6 million pounds of airborne emissions that exceeded state limits, according to an analysis by the Environmental Defense Fund, Air Alliance Houston, and Public Citizen. Federal and state regulators say their air monitoring shows no cause for alarm. At least 14 toxic waste sites were flooded and damaged, raising fears of waterborne contamination. Nearly 100 spills of hazardous substances have been reported, said The New York Times. OG
OIL&GAS ENGINEERING
SENIOR CONTRIBUTING EDITOR
I NSIDE COVER STORY 6
Cover image courtesy: Schneider Electric
6
Embrace control room technology innovation Tips on how to do more with what you’ve got; look to the future
FEATURES 10
Practical approaches to rigorous corrosion protection Across industry sectors, wide application possible
14
10
Canada’s pipeline regulator revises quality programs Response to detection of inappropriate materials used in fittings
NEWS 16
Oil & Gas Industry News Remote, direct-monitoring system for flares Integrate seismic workflow and decision-making Cased-hole evaluation system for enhanced recovery
OIL&GAS ENGINEERING OCTOBER 2017 • 5
IIoT In mIdsTream oIl & gas
Embrace control room technology innovation Tips on how to do more with what you’ve got, look to the future By lars larsson and Collin Heggerud
I
t was for safety’s sake that control room management (CRM) regulations were introduced into the oil & gas pipeline industry. Yet, over time, to achieve a comprehensive view of operations, more and more alarm states were introduced. By replacing simple high-level and low-level alarms with alerts for practically anything and everything, an environment was created that too often overwhelms. CRM regulations were created with good intentions, to fix controller overload and provide for industry uniformity. However, it’s time to stop playing catch-up based on outdated regulations and innovate based on today’s technology. For pipeline management, the Internet of Things (IoT) means more data is available than was ever thought possible. While this granular pipeline information can lead to a better understanding of an operation’s health, much of it isn’t used and thereby lacks value. An opportunity exists to better use existing data to create safer, more profitable operations. Value can be found in data already captured, while looking ahead to how the technology is evolving. Revisiting existing technology to increase its profitability is a useful exercise, even with tools already in hand. Doing Big Data small IIoT brings intelligent sensing and control to the process and empowers connectivity. But because data is generated or transmitted in aggregate, the overall data burden is lessened, introducing new opportunities. The application of analytics to these simple data sets can lead to improved productivity. Consider the following examples.
6 • OCTOBER 2017
OIL&GAS ENGINEERING
Pump-station sensors provide readings at high-frequency intervals. Aggregation and analysis of these readings can yield information useful in optimizing operation and reliability of pump-station turbines. Most door locks on remote terminalunit shelters are monitored already. The advantages of applying analytics may not be apparent. Yet by making these locks into online devices a very small dataset can be monitored to answer two important questions: “Did I remember to lock the door as I left the shelter?” and the follow-up, “If I forgot, can I lock it remotely?” Recently, an industry supplier wanted to monitor, in “near real time,” its client’s remotely installed tank that was located outside of cellular coverage. However, the potential return-on-investment did not justify significant data transfer over satellite. Instead, it was decided to sample the tank levels only once per day. Few data sets are smaller than a single analog value once-perday. Nonetheless, the present arrangement provides grist for relevant, knowledge-based decision making. Tank-level example Tank-level measurement is another area where simple but meaningful improvements are possible. Gauging tank levels is among the simplest of measurements. Yet from that single measurement, simple calculation is then used to determine tank fluid volumes and space remaining, otherwise known as “ullage.” Daily consumption rates are easily calculated and then setpoints determined to generate alarms for rates above or below target. Rates above target could signal a possible leak and lost product. Rates below target could indicate a possible pump
malfunction, resulting in lost revenue and upset customers. In one case study, monthly volume and revenue versus expected-volume were calculated, as well as the number of days until tanks were expected to empty, to alert users to fill the tanks. After that, users devised a function that calculated the optimal amount to add to the tank to achieve a target inventory that minimized total costs of refilling the tanks with carrying inventory. The potential remains to do more. What about calculating the total volume added for the month? What about the total volume carried for the month in relation to inventory costs? Real-time regimens Stepping back from this simple example, what if the same level of analysis was applied to every data point in a real-time system? Use possibilities extend far beyond what is typical today. We should not only be storing more live values, but doing more with the live data we already collect. Today’s real-time systems should automatically collect and perform additional analysis of larger volumes of historical data. The analysis should include basic statistical measures as well as simple calculus. This would mean that that flow rate is a derivative and inventory carried is an integral. It should also measure what other values exist, such as, “Is the derivative of the flow rate useful for the business?” While mathematical functions provide value, it often takes human reasoning to understand their significance. The demand for real-time data inside and out of the control room is greater than ever before. Too much of a pipeline controller’s time is spent communicating SCADA data to field workers. Calling the control room for SCADA data seems like an outdated practice given the current state of technology. Technology is the intermediary in this situation, with mobile access to that data. Steps taken in this direction ease controller overload and distraction, allowing focus on pipeline-operations safety and efficiency.
HTML and SCADA Using HTML for SCADA data is another way to increase efficiency through mobile data accessibility. By incorporating web-browser accessibility, enterprise visibility of pipeline information is brought into modern times. With the ability to reach more desktops and devices, HTML has major potential in the pipeline oil & gas sector—both in the office and out in the field. Display technology has changed over time. Fancy, complex colors and graphics were once considered a great selling point for SCADA system displays. However, just as with adding alarms, these extravagant, complex displays proved a distraction and less safe than some alternatives. Operations can benefit from modern display technology, which are based on decades of experience with user interfaces. If everything is running smoothly, displays should be non-eye-catching, with only high priority situations highlighted as required. Training is easier too with an easyto-understand view of operations. Even people who do not have control room experience should understand basic displays. For example, if you wear a heartrate monitor during exercise and it tells you that you have a heart rate of 136, that probably means nothing by itself. But, if you can place the heart rate in the context of normal heart rate ranges for an average person your age, then you can decide whether you are exercising too strenuously.
Control-system display technology has changed over time. Loud colors and complex graphics were once considered appropriate. These extravagant displays are now judged to be potentially distracting. All images courtesy: Schneider Electric OIL&GAS ENGINEERING OCTOBER 2017 • 7
IIoT In mIdsTream oIl & gas Maximization of existing data sets and the streamlining of control room technologies is important in attracting and training a new generation of employees.
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Moving towards innovation in the control room, while making the most of data already available, is especially important with the “great crew change” on the horizon. With much of the industry’s workforce expected to retire within the next five years, companies must find a way to attract and retain young employees with technology. The younger generation has grown up with technology and are attracted to new ways of exploring it, but need tools to present information in a simplistic, easy-to-understand format. Brief summation In the attempt to enhance safety in the face of automated alarm controller overload, an environment has been created that is rife with distractions and potentially confusing displays. In the short term, the focus must be on maximization of existing data sets and the streamlining of control room technologies. It’s important in attracting and training a new generation of employees. Finally, pipeline enterprises will move past control room regulations to create an environment that is safer and ultimately more productive. OG Lars Larsson is a senior product manager at Schneider Electric. He has more than 22 years of experience in the oil & gas industry.
NEC Rated · FM/CSA Approved
Collin Heggerud is a director of product management, SCADA, with Schneider Electric. He has been involved in technology development for the oil & gas industry for more than 20 years. 8 • OCTOBER 2017
OIL&GAS ENGINEERING
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Maintenance of infrastructure assets
Practical approaches to rigorous corrosion protection Across industry sectors, wide application possible
C
By Julie Holmquist
Figure 1: Hot layup of risers on a drillship using waterborne VCI fogging and capping with film. All images courtesy: Cortec Corp.
orrosion is a persistent challenge in all oil & gas industry sectors: upstream, midstream, and downstream. This is due not only to the corrosiveness of the materials exploited, but also to the harsh environments many structural and equipment assets are exposed to in oil & gas production, transport, and processing. High costs, safety hazards, downtime, and additional labor result. According to NACE International, total annual corrosion cost in oil & gas production is about $1.4 billion, with roughly $590 million assigned to surface pipeline and facility costs, $460 million to downhole tubing expenses, and $320 million to capital expenditures. Some aspects of corrosion that could be better controlled are completely overlooked or inadequately addressed. For example, millions of dollars’ worth of spare equipment sits idle in gas or oil facilities around the world. Too often, a lack of sufficient preservation technology and expertise leaves these assets at the mercy of harsh outdoor environments. Volatile corrosion inhibitor (VCI) technology and related methods enable more effective protection. VCIs are typically easier to use and more environmentally friendly than many traditional treatments. A brief survey The upstream sector explores for and procures crude oil and natural gas using oil rigs, drill ships, and offshore platforms.
10 • OCTOBER 2017
OIL&GAS ENGINEERING
Corrosive attacks come both from the nature of the resources used in drilling and from the corrosive environments in which drilling is performed, including, for example, offshore salt-spray conditions. Practically any metal structure or piece of equipment is at risk for corrosion in these circumstances, from polished bore receptacles and offshore platform caisson legs to valves, pistons, pumps, electricals, and fire extinguishing systems. In addition, market volatility often brings long periods of layup, which put the equipment at risk for corrosion, if not adequately protected. The midstream sector focuses on oil & gas transportation involving millions of miles of pipeline around the world. Corrosion can start at the pipe-manufacturing plant long before pipeline construction begins. Typically, pipes are left unprotected, or a wax-like coating is used that is challenging to thoroughly apply on internal pipe geometry and equally difficult to remove. Corrosive conditions may worsen as the pipes are transported through different types of weather and, in many cases, undergo salt-spray conditions while being transported overseas topside on ships. On land, some pipeline projects take years to complete, during which time pipes sit in unsheltered pipe yards. Welders coming to couple the pipes together have additional work cleaning any corrosion off the to-be-welded surfaces. Downstream facilities face similar corrosion problems but often on a larger scale due to the oil & gas volumes involved. Downstream facilities keep spares on hand ready for quick replacement of a failed part. Often, though, spares are stored outside on open racks and subject to corrosion. Thousands of aboveground storage tanks risk corrosion on tank bottoms and need to be protected against possible leakage. Basic
facility assets such as boilers, coolers, pumps, valves, engines, insulated pipes, and structural steel are also at risk during mothballing or facility construction. Ways to the means Steps to prevent corrosion are not necessarily difficult, if the proper precautions and proper technology are used. By active vigilance and the use of VCIs, corrosion can be reduced in a cost-effective, often more environmentally friendly manner than is otherwise the case. VCIs are commonly made of organic salts of carboxylic acids. They work as mixed inhibitors to protect against both anodic and cathodic reactions of a corrosion cell. In use, VCI inhibitor molecules vaporize from a source material until they reach equilibrium in an enclosed space. The VCI molecules are attracted to and adsorb on metal surfaces to form a hydrophobic layer that protects the metal from interaction with corrosive contaminants. When the enclosure is opened, the VCIs will dissipate from the surface, leaving the metal corrosionfree and ready to use. On the other hand, if the space is only temporarily opened and enough source material remains, the protective layer will replenish on the metal surface and protection will continue after the openings are closed again. Because of their vapor activity, VCIs work in multiple phases. Like traditional contact corrosion inhibitors that are added to liquids, they can dissolve and protect metal surfaces in contact with the liquid, including, for example, the insides of a pipe or tank below the surface of the fluid. VCIs also can protect metal surfaces in the void space above the fluid and at the vulnerable interface where the air and fluid meet. VCIs protect against micro-corrosion and corrosion creep. Many coatings rely on zinc, chromates, and other heavy metals to work. However, the large particle sizes of these substances leave gaps in the coating that can allow corrosion to start in micro-cavities and more easily spread. VCIs protect against this and discourage corrosion spread if the coating is marred by a scratch or dent. VCIs can be incorporated into other mediums such as liquid forms for pipes and tanks, powder forms for void spaces, packaging materials for wrapping equipment, removable
or long-term coatings, foams, and papers. Versatility allows for a tailored approach that considers length of protection and ease of removal. Applications in oil & gas A sound corrosion plan preserves assets in all three sectors of the oil & gas industry. A variety of application methods may be used to develop a spares layup strategy that requires very little labor and time to re-commission. Across all oil & gas sectors, a common application method is equipment shrink-wrapping using polyethylene film containing VCIs. The film is made to different durability levels depending on the indoor or outdoor storage situation. Foaming or fogging are added as needed based on the volume of the space being protected. Equipment stored in this manner can be unwrapped and re-commissioned relatively quickly, typically without the need to clean off traditional petroleum-based coatings that may be classified as hazardous waste. VCI film can be recycled and in some cases turned into new film. This is useful for standby layup of spare equipment as well as for long-term mothballing of entire plants. These methods are preferable to traditional layup strategies, such as potentially dangerous nitrogen blanketing or dehumidification systems that require monitoring and a constant source of electricity.
Figure 2: VCI molecules evaporate from a source, fill an enclosed space, and adsorb on metal surfaces to protect them from corrosion.
Upstream structural corrosion To protect against exterior structural corrosion in the upstream sector, VCI coatings can be used in offshore platform layup projects. These types of coatings protect with a relatively thin film, making them more versatile and reducing labor and materials. For internal structural protection, the addition of waterborne and powder VCIs proves highly effective. In a two-year trial inside an offshore platform OIL&GAS ENGINEERING OCTOBER 2017 • 11
Maintenance of infrastructure assets
Figure 3: Corrosion inhibitor being applied to caisson legs.
caisson leg, a reduction in corrosion rate compared to the control caisson leg was demonstrated. It is important to ensure electricals and electronics are in good working condition, preserved from corrosion. This can be done by sticking a self-adhesive cup filled with VCIs inside an electrical or electronics enclosure. The VCIs escape through a breathable lid and fill the enclosure, forming a self-replenishing protective layer on the metal surfaces. Another option is to spray electrical panels with a VCIenhanced coating formulated for indoor or outdoor conditions. The corrosiveness of downhole drilling operations is well-known. VCIs have been formulated into chemistry that can create a persistent anti-corrosive film barrier in these structures to protect against water intrusion, pitting, and corrosive gases. The VCI components of the chemistry provide additional protection for any portions of the downhole structure not in direct contact with the fluids. It can be used in both sweet and sour conditions, that is, low or high hydrogen sulfide concentrations. Firefighting systems aboard offshore rigs are another critical point of protection. These systems often rely on water pumped directly from the sea, which is highly corrosive. If corrosion occurs between testing periods, the system could malfunction when it is needed. Systems using VCIs have been devised to protect against corrosion of these critical firefighting devices. Midstream pipeline protection Early corrosion protection of newly manufactured pipes is an important step for maintaining pipelines in good condition from the start. This can be done by fogging pipe internal diameters with a waterborne VCI, capping the ends with VCI film, and coating the outer diameters with a waterborne VCI coating that can be removed or left in place as desired. Weld-site
12 • OCTOBER 2017
OIL&GAS ENGINEERING
coatings reduce the time and effort welders normally require to obtain a clean welding surface. Coating can be washed off with an alkaline cleaner (preferably containing flash corrosion inhibitors), leaving the welder with a clean surface. The same protection strategies apply to pipes already onsite once cleaned of the typical buildup of dust and debris. On an in-service pipeline, the technology has the potential to protect the pipe against internal corrosion on 360 degrees of the inside diameter as the fluid flows through the pipe. This comprehensive protection potential is due to VCI multi-phase characteristics. A traditional corrosion-inhibiting additive in liquid gas or oil streams would only protect the pipe walls in contact with the oil or gas. Here, protection of the entire pipe-wall circumference is achieved. Environmentally friendly pipeline casing fillers have been developed that protect the annular void spaces between pipelines and their casings. The gel filler is a unique alternative or backup to traditionally used cathodic protection because it protects with or without the presence of an electrical current. The vapor action allows VCIs to migrate under disbonded coatings and provide corrosion protection to inaccessible and recessed surfaces. Development of the method was inspired by the request of a North American pipeline corrosion engineering group. The technology has been patented in the U.S. It also can be used in other tubular structures. Downstream strategies Downstream layup strategies are like those already described for spares layup. Preservation of the many spare parts that may be lying on outdoor racks is an important step to downstream asset preservation. This is a growing trend, and many major oil & gas facilities today are preserving everything from the smallest screws to the largest equipment using films, coatings, emitters, and fogs. When the parts are needed, it is easy to unwrap them, recycle the film, and install or re-commission the parts. Oil & gas facilities also include aboveground storage tanks that require protection from corrosion on tank bottoms. Risks from corrosion include leakage and environmental contamination but can be countered using VCIs
found to be compatible and even synergistic with cathodic protection (CP). VCIs injected beneath the tank bottom work to protect areas not in contact with the CP’s conductive electrolyte, while in certain cases the CP may enhance the effectiveness of the inhibitor. VCIs can be added to tank pads before construction or injected below existing in-service or out-of-service storage tanks. Downstream systems such as piping or electronics benefit from proactive corrosion protection. VCIs can be injected into insulated piping to protect against so-called corrosionunder-insulation. Emitters added to electrical and electronic instrument boxes can be a simple protection against the extra costs of electrical repairs, malfunctions, or downtime. Coatings can be used on a variety of structures and equipment. Industry changes Corrosion is everywhere in the oil & gas industry. Fortunately, practical methods for UEC_Vanguard Ad_Oil-GasEngin_09-17.pdf
protection of assets are available today that were once overlooked. VCIs enable more thorough protection in void spaces using vapor-phase action. They enhance coatings performance by protecting against microcorrosion, and reduce need for materials that must be disposed of as hazardous waste. Instead, they are typically recyclable or easy to remove and discard. They preserve important assets during common waiting periods prior to construction or when a volatile market warrants layup. They have forged important ground in the layup of equipment for major oil & gas companies globally and will continue to be an important source of providing cost-effective preservation to the industry. Special thanks to Bob Boyle, Jim Holden, Eric Uutala, and John Wiermaa of Cortec Corp. for their firsthand insights on corrosion in the oil & gas industry. OG Julie Holmquist is content writer at Cortec Corp.
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PiPeline safety and security
Canada’s pipeline regulator revises quality programs Response to detection of inappropriate materials used in fittings
I
n recent months, Canada’s National Energy Board (NEB) has expanded the scope of its previous safety advisory and draft order regarding the quality assurance of pipeline materials. In late 2015, the Transportation Safety Board of Canada (TSB) released a pipeline investigation report on a 2013 gas pipeline rupture incident that concluded the pipeline failure was due to the pipeline operating beyond its temperature design limits. However, during the investigation, the TSB also noted that fittings used on that pipeline contained materials that did not meet the appropriate specifications. While these fittings were not the incident’s direct cause, they raised a red flag and the NEB began investigating the issue immediately. The NEB is an independent federal regulator of several parts of Canada’s energy industry, including pipelines, energy development, and trade. It does so in the public interest, with safety as its primary concern. At the moment, it also is embroiled in a controversy concerning the review of the proposed Energy East pipeline.
Unfolding narrative In February 2016, the NEB issued two safety advisories and an order that required NEBregulated companies to identify and report on purchased and installed pipeline components that contain material properties that do not meet standard associations’ requirements. Subsequently, the NEB became aware of additional quality issues associated with pipeline fittings. According to Reuters, the push for a shift in standards for pipeline parts came after TransCanada Corp and Enbridge Inc. discovered some that they were using were substandard. The NEB in April warned about parts from Tecnoforge, a subsidiary of Italy’s Valvitalia SpA, and South Korea’s TK Corp., but did not name the companies using them. TransCanada and Enbridge said in separate statements that they acted immediately and proactively after discovering the issues and that all their pipes were safe. 14 • OCTOBER 2017
OIL&GAS ENGINEERING
In April, the NEB issued an amended safety advisory and order. The amended advisory expands the scope of the previous one by naming additional manufacturers whose components did not meet requirements. The draft order will require NEB-regulated companies to identify components fitting this description, confirm they are safe, and take appropriate mitigation measures. Impact assessment The NEB’s Onshore Pipeline Regulations Section 23 of 23 requires regulated companies to conduct pressure testing on all pipe and fittings before they can be connected to a pipeline system. In all cases fittings are pressure-tested to at least 25% above maximum operating pressure. The NEB expects regulated companies to demonstrate a proactive commitment to continual improvement in safety, security, and environment protection, and to promote a positive safety culture as part of their management systems. To support these expectations, the draft order will require companies regulated by the NEB to: • Verify components having material properties not meeting required specifications. • Provide a timeline to conduct engineering assessments that demonstrate the safety of identified pipeline components installed in operating pipelines having material properties not meeting the required specifications. • Provide a timeline to revise the company’s quality assurance program, as required under section 15 of the NEB Onshore Pipeline Regulations, which is aimed at preventing the installation of pipeline components with material properties not meeting the required specifications. • The company’s accountable officer must file a written confirmation certifying that the engineering assessments have been completed and the quality assurance program has been revised. After reviewing the received comments and making changes where appropriate, the NEB will finalize the draft order. OG
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OIL & GAS INDUSTRY NEWS Environment combines domain expertise and digital technologies
Field-data capture solution enhances back-office collaboration
Dover Energy Automation announced an enterprise solution it says has the power to simplify challenges that executives face while evaluating equipment reliability and efficiency. Windrock Enterprise provides remote visibility of an entire fleet of assets. This is a dramatic improvement compared to the previously limited and incongruent views of data collected from singular pieces of equipment whose connection methods isolated them from the remainder of the fleet. Essentially, from any computer or mobile device in the world, enterprise stakeholders with proper credentials will have on-demand access to a modern and intuitive dashboard where they can gain crucial insights about asset health. Visibility enables executives to make more informed decisions based on key performance indicators. This metric-based decision-making can help unlock widespread optimization opportunities across the enterprise. Windrock Enterprise uses Microsoft Azure IoT Technologies. The solution also leverages the Azure Infrastructure-as-a-Service (IaaS) and Platform-as-a-Service (PaaS) to provide IoT solutions in the rigorous world of industry. OG
P2 Energy Solutions announced the release of P2 Field Operator 1.0, which combines field-data capture and operations management software with mobile capabilities to simplify field operators’ daily challenges of managing large portfolios of remotely located wells and equipment. P2 Field Operator enables quick data validation, image capture, and seamless collaboration between the field and back office. By connecting key stakeholders across the field and back office, P2 Field Operator allows operators to reduce deferments and improve operational efficiencies by identifying and reporting production problems faster. In fact, studies show that with P2 Field Operator, time spent on field data capture and reporting activities can be reduced by 40% or more. When combined with operational intelligence capabilities, P2 Field Operator makes pumping by exception possible by giving operators the insights needed to prioritize tasks and routes. For example, if two wells are down at the same time, pumpers can decide which one to attend to first based on surveillance rules that monitor the collected data and initiate alerts. Operators can then deviate from the prescribed route and focus on the wells that need more urgent attention. OG
Rugged tablet is built for performance and security The Getac A140 fully rugged tablet is equipped with a 14-in., 1,000 nit sunlight-readable display, available Intel Core i5 and i7 processors, dual hot-swappable batteries for continuous use, and a suite of security features. The A140 is a robust, purpose-built, rugged tablet for industry. The optional multifunction hard handle serves as a support stand and cradle when working and an effective way to grab-and-go when time is critical. “With the introduction of the A140, customers will now have access to the largest fully rugged tablet we have ever produced. The ability to quickly see more data on the screen is exactly what our customers have been looking for. Advanced security features, fast performance, and an outdoor viewable screen make the A140 one of our most exciting launches,” said Scott Shainman, president of Getac. OG 16 • OCTOBER 2017
OIL&GAS ENGINEERING
Openness and extensibility allow intellectual property infusion Schlumberger unveiled the DELFI cognitive E&P environment, which enables collaboration across exploration and production (E&P) teams, leveraging digital technologies for security, analytics, machine learning, high-performance computing (HPC), and the Internet of Things (IoT), to improve operational efficiency and deliver optimized production at the lowest cost-per-barrel. The DELFI environment strengthens integration among geophysics, geology, reservoir engineering, drilling, and production domains. The openness and extensibility of the DELFI environment will enable Schlumberger customers and software partners to add their own intellectual property and workflows in the environment. “With the launch of the DELFI environment, we deployed an E&P data lake on the Google Cloud Platform comprising more than 1,000 3-D seismic surveys, 5 million wells, 1 million well logs, and 400 million production records from around the world, demonstrating a step change in scalability and performance,” said Ashok Belani, executive vice president, technology, Schlumberger. As an example, in the Gulf of Mexico, Schlumberger processed highresolution wide and full azimuth seismic data over a 100,000 km2 area in the DELFI environment. Scalable HPC on Google Cloud Platform enabled high-resolution depth imaging using reverse-time migration and fullwaveform inversion technologies, resulting in a significant reduction in project turnaround time. Schlumberger also introduced the DrillPlan digital well construction planning solution, the first step in the DELFI cognitive E&P environment. The solution is part of a fully integrated well construction offering, which transforms planning and execution performance, and enhances the efficiency and quality of every well drilled. The DrillPlan solution leverage the digital technologies of the Microsoft Azure and the Azure Stack hybrid cloud solution. OG
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OIL & GAS INDUSTRY NEWS Integrate seismic workflow and decision-making for optimal production
Cased-hole evaluation system is for enhanced oil recovery
CE 2017-06_TRGuide_MediaShowcase2x4_MII.indd5/17/2017 1 2:23:54 PM
Weatherford International announced the release of the Raptor 2.0 cased-hole evaluation system. The Raptor 2.0 system, which has been tested and proven in more than 200 field runs, combines a pulsed-neutron wireline logging device with advanced petrophysical workflows, a wide range of ancillary products, and support from a team of experienced production petro-physicists to provide actionable reservoir data. The Raptor wireline logging tool features a five-detector array, which makes the system 250% more sensitive than traditional, twodetector pulsed neutron tools. By providing high-fidelity oil-water and gas-liquid saturation measurements, the Raptor 2.0 system enables operators to increase their reservoir knowledge during completion, production, and rejuvenation operations. This knowledge can then be leveraged to increase hydrocarbon recovery. “Today operators are only able to identify and recover a fraction of the oil in their reservoirs. Our new Raptor 2.0 system helps clients look behind the casing to identify the type, location, and amount of hydrocarbons in their reservoir, so they can realize the full potential value of their asset,” said Olivier Muller, vice president of wireline and testing services at Weatherford. OG 18 • OCTOBER 2017
OIL&GAS ENGINEERING
Emerson Automation Solutions launched the latest version of its reservoir characterization and modeling software, Roxar RMS 10.1. Through advances to the seismic-to-flow simulation workflow and versatile decision-support tools, Roxar RMS 10.1 supports optimal decisionmaking and greater ease of use and performance for improved productivity. “RMS 10.1 delivers significant improvements across the geophysics, geology, and reservoir engineering domains; provides highly accurate models and reliable simulations; and ensures that operators make the right field planning and reservoir management decisions for optimal production,” said Kjetil Fagervik, vice president of Roxar Software product development and marketing, Emerson Automation Solutions. RMS 10.1 introduces extended functionalities within the seismic domain, bridging the gaps between seismic interpretation and geological modeling. Displays allow users to co-visualize, compile, and analyze data from multiple sources. Users experience increased performance through more responsive and faster views, and greater interoperability through the Roxar application programming interface. RMS 10.1 now transfers data from the Petrel software platform to RMS in a one-step procedure. Roxar RMS reservoir modeling software is a geosciences and reservoir engineering platform for seismic interpretation, well-log interpretation and correlation, mapping, geo-modeling, gridding, and flow simulation. The software enables operators to integrate their data in one place as a means to improved productivity their workflows. OG
Remote direct-monitoring system for flares Zeeco Inc., maker of combustion and environmental equipment, announced the industrial flare monitoring system FlareGuardian, which meets key U.S. Environmental Protection Agency (EPA) requirements for ensuring flares such as those used in a typical petroleum refinery meet mandated emission standards and operate as efficiently as possible. “The industry has long recognized the known shortcomings of indirect flare monitoring methods, and that knowledge, combined with the new EPA standards and a compliance deadline of January 2019, drove the development of a new flare combustion efficiency (CE) measurement and monitoring method,” said Brian Duck, global business manager, flare systems, Zeeco Inc. This method for flare monitoring has been proven accurate through a series of large-scale validation tests. The technology, known as video imaging spectro-radiometry (VISR), is an advanced multi-spectral Infrared imager that directly and remotely monitors flare performance. In addition to the measurement of CE, VISR also measures and reports the level of smoke in the flare flame day or night to provide the flare operator with a real-time tool to optimize flare performance, resulting in less assist fuel consumption, more efficient combustion, and lower overall flare emissions. Previously, flare operators had been limited to indirect flare monitoring options including gas chromatograph, calorimeters, flare gas flow meters and monitoring, and steam/air controls. The direct monitoring system eliminates the ongoing maintenance and operational costs inherent to indirect monitoring methods and can be installed while the flare is in-service. OG
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