JPT | 14 August 2017

Robot Removes Operators From Extreme Environments

Robots have the potential to move human operators away from uncomfortable, potentially risky environments and into comfortable, safe control rooms. Remotely operated vehicles have already achieved this for subsea fields; however, before this approach can be extended to surface facilities, the robots must be reliable and safe in potentially explosive environments. The Sensabot robot has addressed these challenges and could be the foundation on which future generations of robots are built.

In 2010, a technology plan was prepared that focused on the specific challenges facing projects in the Kashagan Field in Kazakhstan:

  • Climatic temperatures typically ranging from –25°C to +35°C
  • High hydrogen sulfide concentrations in produced gas
  • Raw-gas-injection pressures as high as 690 bara
  • Ice-bound unmanned artificial islands in the winter

These challenges require operators to wear breathing apparatuses and cumbersome insulated clothing in winter that hampers their movement. In summer, the breathing apparatus creates the risk of heat exhaustion.

One contribution to the technology plan was the concept of remotely operated robots. These could remain permanently on location and could be driven by operators located in a safe environment.

The Robot Concept
The first stage of the Sensabot project was to identify the robot’s high-level functional requirements. These fall into three categories: user acceptance, safety, and independence.

User Acceptance. The project team recognized that, although the upstream oil and gas industry has been using remotely operated vehicles for many years in subsea environments, there has been little significant use of robots for surface facilities. The team felt that onshore operators would view the robot with suspicion, so it needed to work reliably to build confidence. By simplifying its functional requirements, the project team could focus on fewer features and decrease the risk of failures.

In this context, it was decided to focus on simple sensing tasks rather than the manipulation of items such as valves and switches. Therefore, Sensabot was designed to perform daily operator inspections of the plant. It was equipped with a range of sensors that replicated those of a human operator (Fig. 1): cameras (sight), gas detectors (smell), a vibration detector (touch), and a microphone (­hearing). Later in the development, a thermal ­imaging camera was added.

Fig. 1—Sensors on the Sensabot.

Another important design decision was to minimize the amount of automation. Sensabot was not designed to eliminate the need for human operators, just to relocate them to a safe and comfortable environment.

Finally, Sensabot was designed to work on plants that have been designed for human operators. Sensabot was scaled to mimic humans (Fig. 2) and to navigate 1-m-wide corridors with 90° corners. This also gave Kashagan management the comfort of knowing that, should Sensabot fail to perform, human operators could readily take over its tasks.

Safety. The overriding safety requirement is that Sensabot should be able to operate in oil and gas environments. In this respect, the project team set its most demanding requirement. Although Sensabot will usually be operating in Zone 2 and explosion-safe environments, it is being certified for International Electrotechnical Commission—Explosive (IECEx) Zone 1 IIB environments (hydrocarbon gas will be present or can be expected to be present for long periods of time under normal operating conditions).

Fig. 2—Sensabot Mark 2 design.

Independence. When establishing the user requirements, it was recognized that there was no point in removing oilfield operators from the field if the robot required frequent maintenance interventions. Therefore, the design goal from the outset has been that Sensabot should operate for at least 6 months without human intervention.

In addition to its reliability, Sensabot needed to be charged while on location. Therefore, an integral part of the robot system is its kennel. The kennel is sufficiently robust to protect Sensabot during transport. Once on location, the kennel is plugged into a 110/240-V power supply. When Sensabot docks in the kennel, a charging connector engages and the operator can switch on the power to charge the batteries for the next mission. The batteries are specified for 3 km of driving, navigating 40 m of rise and fall, and performing 4 hours of sensing operations between recharges.

Challenges and Solutions
IECEx Certification. Conventionally, IECEx certification for explosive environments is applied to simple stationary instruments or containers. However, Sensabot contains 19 different assemblies that need to be certified, 43 in total if duplication is included.

Sensabot Mark 1 attempted to tackle this complexity by installing the majority of these assemblies in an overpressured body. However, this presented a number of technical challenges: The kennel needed to replenish the internal air pressure automatically, the pressure-control valve proved to be unreliable, and leakages around the body’s seals meant that the operational life between replenishing pressure was too short.

Another solution was to use already available certified assemblies. However, because of Sensabot’s small space envelope, most of these were too large.

The approach that was eventually adopted for Sensabot Mark 2 was to design customized assemblies that could be certified individually. This means that the certification process is far more complex than the norm, especially because each assembly must be certified across Sensabot’s full operating range.

Wireless Communications. The wireless link between the robot and its driver is critical if Sensabot is to operate effectively.

Sensabot Mark 1 was designed to operate using a conventional WiFi system similar to that in homes. However, modeling and trials revealed that a large number of WiFi access points would be required to cover even a small production island. More seriously, because of the way WiFi works, the signal to the robot would often be lost when a handoff ­occurred between access points.

A range of alternative wireless networks was evaluated, and the conclusion was that 4G Long-Term Evolution (LTE) networks offered the best solution. While LTE has less bandwidth available per radio than WiFi, it has more than enough to operate Sensabot and an extensive ­network of other wireless instruments. Also, signal loss is progressive and gradual, so, if the driver sees that Sensabot is entering an area with a weak signal, the operator can reverse away ­before the signal is lost.

Sensabot Mark 2 is equipped with both WiFi for small-scale demonstrations and 4G LTE for full operational deployments.

Current Status
Functionality. Sensabot Mark 1 underwent a series of trials in Houston in early 2011. Overall, the trials were a success, with Sensabot proving easy to drive even for inexperienced operators. It performed a wide variety of inspections and traveled many kilometers around the plant, accessing elevated platforms and navigating dark rooms.

However, a number of design weaknesses were identified that have influenced the design of Sensabot Mark 2. In addition to the move away from an overpressured body and the shift toward 4G LTE wireless,

  • Solid tires were replaced with pneumatic tires. These are less prone to wear on metal grids, create less vibration when driving over rough surfaces, and provide better traction across a wide range of surfaces.
  • A move was made from the use of light detection and ranging to stereo cameras to map the surrounding terrain. This is an advantage for Sensabot because stereo cameras can create complex 3D models of the environment that may eventually allow Sensabot to operate with more autonomy. They also can be programmed to detect drops and to intervene before the operator drives over one.
  • A thermal imaging camera was added.
  • Maximum speed was increased from 5 to 7 km/h.

Future Opportunities
Deployment and Benefits. Once Sensabot Mark 2 is certified, the plan is to deploy it at an upstream production facility. Ultimately, the intention is to install the wireless network, kennel, and Sensabot at an unmanned location where Sensabot can fulfill its full potential. However, in the short term, it needs to be tested and proved with a minimum of disruption. Therefore, the entire system, including the control panel, is being built into a shipping container.

Once the container is on location and plugged into a power supply, the system is ready to operate. This minimizes the effect on busy oilfield operators in the early stages of deployment.

Enhanced Functionality. As the project has developed, it has become clear that the components and principles that make up Sensabot could be combined in a variety of packages to suit a range of tasks and operating environments.

For example, as an offshoot of the development program, a manipulation arm was developed and demonstrated. It performed a range of tasks including operating valves and electrical switches. In this respect, it has one major advantage over remotely operated vehicles in that it has massive inertia, a result of its 450-kg mass and low center of gravity. This means it can operate heavy-duty oilfield equipment without special reactive tooling.

Finally, it is entirely plausible that a higher degree of autonomy could be incorporated into Sensabot Mark 2 and future robot generations. An early target will be the incorporation of collision avoidance. Other simple ideas include self-navigation from the kennel to the operational location, auto-reversing in the event of wireless-signal loss, and auto-diagnosis of the sensing data with alarms to alert the operator in the event of anomalies.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181409, “A Robot That Removes Operators From Extreme Environments,” by Ian Peerless, SPE, IPKA Consultancy, and Adam Serblowski and Berry Mulder, Shell Global Solutions International, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.

JPT | 14 August 2017

Integrated Simulation Increases Efficiency of Deepwater Risk Management

As deepwater drilling moved into the dynamic-positioning (DP) era, many drilling contractors and operators lacked an evidence-based approach for identification of potential process-safety and well-control failure points. In an effort to better understand well issues, operational-procedure adequacy, well-control intervention practices, and human factors, a global offshore drilling contractor created a program of fully integrated deepwater-DP-drilling simulation exercises to scrutinize all critical aspects of deepwater well-control operations. The result is a proactive, behavior-based risk-management process.

A Sea Change in Drilling
Beginning in the early 2000s, offshore drilling experienced significant growth in demand. This increased demand, driven by rising commodity prices and the macro­economic phenomenon of rapid economic development in China and India, combined with enhanced technological developments enabling drilling in deeper water, led the industry into a new era.

With the move to deeper water and enhanced DP operations, the industry faced unprecedented demand for drilling units and, therefore, new personnel. In the early 2000s, more than 150 new deepwater mobile offshore drilling units (MODUs) were under construction, creating a need for tens of thousands of new crew members. A sector that had historically hired frontline workers and grown them into drillers and managers over a period of years suddenly needed to hire thousands of new employees each year with virtually no time for them to learn on the job. In addition, both old and new crews were dealing with new technology, resulting in daunting training challenges. Many of the new crew members were going directly to the latest and most-complex rigs being built.

New Approach to Training Needed. The effect of all this change and innovation on crew development has been pronounced. Research indicates that technology-intensive systems require considerable operator and crew expertise for effective use. But drilling operations also require the wealth of tacit (undocumented) knowledge that many long-term drilling professionals possess. The older and newer generations do not necessarily share a mental model for tasks that require their collaboration, and any given task may itself involve hundreds of steps that have become automatic for people with long experience but that often have not been recorded because of the long-standing practice of on-the-job training.

While technical-skills training remains vitally important, teamwork and interdependence among drilling, DP, and power-management crews on DP MODUs remain critical to process safety. The merging of groups of professionals from these different disciplines into an integrated team capable of working collaboratively has become more important than ever. The company recognized that the most effective training programs for DP MODU operations must address both the individual technical skills and competencies and the human factors necessary for safe and efficient operations.

The challenge was to build an environment and process to bring this diverse group of skilled professionals together to work collaboratively toward the shared goals of delivering safe and efficient wells in deepwater settings. The goal was to make collaboration easier by reducing the potential for error and miscommunication; increasing operational efficiency; and customizing the design to match realistic equipment, well, and environmental drilling situations. Effective training of this caliber would translate into cost savings and safer operations. The company turned to immersive simulation environments to deliver this training.

Fig. 1—The drill-floor simulator replicates the rig design and equipment.

New Approach to Training Initiated. In 2010, the company obtained its first simulator. Created to support an entirely new rig design, the simulator was built to replicate rig drilling-control systems and rig floor layout exactly. The simulator is a fully immersive, theater-style driller’s cabin with two chairs featuring supervisory-control and data-­acquisition displays, closed-circuit-television screens, and choke and kill and blowout-preventer controls. The visual depiction of the drill floor was programmed to replicate the as-designed rig, including all original-equipment-­manufacturer-specific ­drilling-equipment functions (Fig. 1).

Training Designed To Address Human Factors. Significant documented support exists for the efficacy of using simulations in team training. Simulation exercises are effective in training for drilling operations for several reasons:

  • Time pressure is built into simulation. Time pressure is a key factor in drilling situations and a critical component affecting decision making. By contrast, the white board in the conference room conveys no sense of time or urgency, although it may serve well in presenting certain types of information or in leading a discussion.
  • Simulation is an efficient method of training because various activities are integrated throughout the exercise rather than being presented separately and stitched together in other formats.
  • In a simulation, it is possible to create scenarios concerning a specific problem.
  • A simulation is likely to be preferable for action-oriented, hands-on people.
  • Because it replicates the many simultaneous actions, reactions, and interactions that occur in both normal and crisis operations, a simulation presents a better replication of those operations.
  • Debriefing provides a step back for participants to review actions and decisions and determine the best path to follow in future situations, to address team and behavioral issues, to redesign communications protocols, and to raise procedural issues.

Integrated Operations Exercises (IOE)
The IOE process was designed by the company to enhance safe and efficient performance. It was built around the three chief operating systems on a DP MODU—drilling, station keeping, and power management. These three systems are where the primary threats to process safety—loss of well control, loss of position, and loss of power—can occur. While the training center could simulate all three of these variables independently, the goal for IOE was to create a realistic whole-rig simulation where the threats and potential failures of major systems are interdependent.

The simulations are enhanced through the use of the sounds and ambience of typical day-to-day drilling, including machinery noise; distractions in which individuals are called away to attend to other duties; public-address announcements; mud-weight checks; and, importantly, intervals when little or nothing is changing, which create opportunities for boredom, complacency, and lack of vigilance.

The IOE simulation represented the best means to improve operational safety and efficiency. Evidence-based training gives the company a laboratory for observing critical operational procedures and human factors. Running the IOE internally several times revealed that the training model would be highly valuable for collaborative training with customers, making it an effective and efficient preoperations planning tool, augmenting or replacing the traditional “drill well on paper” with “drill well on simulator.”

Joint-IOE Results and Benefits
The joint IOE accelerated crew relationships and understanding of communication styles and expectations, correlating to improved well delivery. The actual-well performance reflected more-efficient work coordination; the well came in under budget and 19% faster than the estimated time frame. Nonproductive time was only 10.6%, and a high percentage of that was waiting on weather. The well was planned for 60 days; it was completed in 49 days. Operator management concluded that operational efficiency and performance were the result of better interaction and communication between the operator and company crews and managers.

Improvements in human-factors performance noted by the operator included better collaborative risk management, understanding personal communication and decision styles, and gaining a better understanding of individual-crew capabilities. The simulation exercise significantly reduced the learning-curve time for establishing planning, decision-­making, and risk-management prioritizations between the operator and the drilling contractor. Specifically, the exercise enabled the operator to understand how the rig manager, tool pusher, captain, and engineers work together. The process enabled the operator to see the competencies of the drilling-contractor crew under realistic scenarios. Further, the simulation exercise gave practical experience for the interface between the operator and the drilling-contractor crews.

The benefits of team training have been documented in a large body of research across industries and over time. Team training addresses behaviors and dynamics to effect good working relationships, enhanced situation awareness, streamlined communications, improved flexibility and adaptability, and better identification of human-factors issues that affect operations. Further, operational efficiencies and process safety are improved by allowing for better prewell planning and for human factors to be addressed. The results of the IOE further support the existing research in these areas.

The simulation exercise with integrated software provides a platform for the creation of new protocols. The training helps teams eliminate unnecessary steps in planning and related delays, resulting in shorter time to efficiency. Simulation increases operational safety and efficiency by promoting teamwork between key individuals while they are experiencing simulated system faults, failures, and well-control problems. In addition to uncovering possible technical issues, the training is used reliably to predict other areas of possible difficulty in actual operations.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180351, “Deepwater Well Control: Integrated Simulation for Risk Management,” by Fritz Golding, Noble; John Spath,Talos Energy; and Bob Newhouse, Newhouse Consultants, prepared for the 2016 SPE Deepwater Drilling and Completions Conference, Galveston, Texas, USA, 14–15 September. The paper has not been peer reviewed.

JPT | 14 August 2017

Company Integrates Human Factors Into Corporate Well-Control Manual

Many of the worst oilfield incidents have been attributable to human factors. Consequently, a corporate well-control manual was refreshed to include human factors in the management of well-control incidents. This required mapping the well-control process, assigning specific roles to personnel, and defining contingencies while acknowledging the effect human factors have on the personnel involved. The intention was not to create a rigid structure but rather to provide a framework to guide the front line in dealing with a well-control event.

The corporate well-control manual was updated to introduce human factors and consolidate a number of improvements. Numerous references were consulted, including other industry well-control documents, trade publications, and academic papers.

“Human factors” refers to technological, organizational, and job factors, as well as human and individual characteristics that affect how people perform a job. It includes the competence and behavior of personnel, the design and functionality of equipment, and organizational structure and support.

Why was it necessary to include human factors in something as fundamental as a well-control manual? Many diverse challenges are faced in well control, often involving multiple complex interfaces in a high-stress environment. Frequently, the problem is not fully understood, either. The challenges of decision making in such a pressured environment have been recognized in other industries, and they share many similar features.

The recognition in the drilling industry to include human-factors mitigation into emergency management and, specifically, well control was one of the outcomes of the Macondo disaster. Recognizing the importance of this, a Human Factors Task Force was established to identify improvements related to human factors and their contribution to such incidents. Training- and competence-assurance guidelines were issued, and objectives were set to provide a step change.

Human Factors in Well Control
Well control is often a stressful, high-risk situation, and it is important to understand the effect of how people perceive and react to a well-control situation.

Mental Traps. Managing a well-control situation is stressful, and a number of mental traps need to be dealt with for a successful outcome. These traps are common in situations similar to well-control incidents, and they increase under time pressure or when people become fatigued because of long periods of stress, both of which are experienced frequently in a well-control incident.

Cognitive Biases. A cognitive bias typically occurs when information is interpreted and an attempt is made to simplify complex information.

A cognitive bias may also be seen as a tendency to confirm some preconception or possibly discredit some information that does not support an entrenched view. Such biases have a major influence on the ability of both the individual and the team to understand what is happening during a well-control operation.

Situational Awareness. Situational awareness is understanding the current state of a system and anticipating future change. This is required to perform safely and efficiently, and it is crucial for good decision making and good leadership and for a team to work together to resolve well-control situations. Not considering situational awareness creates a higher risk of poor decision making.

Human factors become even more important when considering the way the drilling industry conducts business, especially in the current downturn market (e.g., short-term contracts, personnel with varying expertise changing out regularly, personnel with diverse cultures and backgrounds and unknown and varying levels of experience, nonstandardized methods, different management systems, regulations).

Clearly, it is essential to include ways to integrate human factors into the well-control-management process. The challenge was how to embed an esoteric concept in a simple, easy-to-use well-control reference document.

Human-Factors Approach to Incident Mitigation
Consideration for human factors in the design of systems is centered on the end user. Systems are designed to fit the physiological limitations of the people tasked with managing them. The design includes features that improve comfort and productivity, minimize errors, and minimize training time.

The problem faced when incorporating human-factors psychological phenomena with various management policies and procedures into a standard well-control manual was how to develop and integrate these into specific tasks and procedures and identify what training is required.

Implementing significant changes in how things are done in an industry generally resistant to change requires tact, education, and training. This is a continuous process achieved by integrating human factors into the well-control manual, integrating the well-control manual into training, and providing offshore well-control simulators.

Some of the key considerations used when developing the well-control-management process are

  • The well-control operation had to remain within the safety envelope at all times.
  • The well-control-management process needed toMitigate plans drifting in critical situations.
    • Help combat mental traps and human errors.
    • Encourage good situational awareness.
    • Facilitate nontechnical skills and help maintain correct decision making.
    • Facilitate good team resource use and provide better leadership overview.
    • Facilitate better communication.
    • Encourage team feedback.
    • Increase the ability to identify deviations from expected outcomes or trends.
    • Improve the team’s big-picture visibility and the individuals’ roles required to achieve it.
    • The process had to be rig friendly and ensure the buy-in of all stakeholders, including clients and other third-party vendors.
  • Once these were established, the next step was to map the well-control process using the following guidelines: what happens, who does what and when, what equipment will be involved, and what the expected outcome is.

Mapping the Well-Control Process
The approach taken in mapping the well-control process was to keep human factors central to the operation. It is not an add-on; rather, the entire process has been designed to incorporate human factors.

Mapping created the following phases:

  • Confirm the well is shut in; verify initial shut-in pressures and pit gain.
  • Monitor well continuously for anomalies.
  • Shut down other activities.
  • Gather logs and other relevant information.
  • Convene meeting by offshore-installation manager.
  • Discuss the well-control event, seeking assistance if necessary, and agree to kill the well.
  • Begin well kill as planned.
  • Monitor the kill against expectations; any deviation requires re-evaluation.

Well-Control Procedures. Mapping the well-control process provided a series of phases. To facilitate integration and adherence to these, it was essential to incorporate them into a series of easy-to-follow procedures. Steps were detailed with actions (what needs to be done), responsibilities (who does it), specific focus area (what equipment or procedure will be used), strategy and plan (how to do it), and comments.

Additional Strategies
Even the most-detailed procedures may be insufficient on their own to control a major risk such as a well-control incident. There are many other threats, and several additional tactics were incorporated to mitigate them.

Closed-Loop Communication. This is a communication technique used to avoid misunderstandings. The sender gives a message, the receiver repeats this back, and the sender confirms the message. Verbatim repeat-back, or closed-loop, communication is to be applied to all critical communication and will mitigate cognitive bias.

Devil’s Advocate. A devil’s advocate is someone who argues against an opinion not as a committed opponent but simply to determine its validity. It is incorporated to minimize the risk of developing normalization of deviance and groupthink. It will mitigate the tendency for cognitive bias.

Fingerprinting and Trending. Fingerprinting establishes baselines for various operations. It is common practice in certain wells and other challenging operations and is typically done inside the casing before drillout of the shoe. The practice, however, may be applied to any situation and should be encouraged in other operations. This assists in the identification of well-control incidents and other incidents. Fingerprinting and trending will improve situational awareness by providing a baseline to be measured against.

Understanding trends plays a crucial role in early kick detection and well control. It is in everyone’s interest to understand equipment and well behavior, to identify problems as early as possible. Trending against what “good” or a modeled “expected” looks like is a very powerful tool for identifying anomalies. Fingerprinting and trending coupled with “what does ‘good’ look like?” makes a powerful tool.

Forward Projection. Forward projection is establishing what a system should look like. This may take the form of computer modeling or just simple calculations. It defines what “good” and “bad” look like. It is impossible to know abnormal unless one knows normal.

Forward projection should mitigate situational awareness and will assist in mitigating cognitive bias.

Well-Control Pullout Pack. The Well-Control Pullout Pack is a folder containing up-to-date pertinent information for the well. This includes inter alia details on blowout-preventer and rig-equipment conditions and any outages, detailed well information, third-party-equipment information, kick sheets, mud and pit information, and shut-in and well-control details.

It is important to ensure that accurate and up-to-date information on the well and the rig is always available. The Well-Control Pullout Pack is designed to mitigate potential oversights, facilitate communication, and provide a checklist containing detailed information about the well, updated procedures, and the status of the rig and other equipment.

The well-control process has been mapped, and human-factor considerations were successfully integrated into policies and procedures.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184648, “Integrating Human Factors Into Well Control,” by Jacob Odgaard, SPE, and Tim Morton, SPE, Maersk Drilling, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, 14–16 March. The paper has not been peer reviewed.

Summit Safety Group | 10 August 2017

Video: Still on OSHA’s Table for 2017

There are still plenty of regulations from the Occupational Safety and Health Administration (OSHA) to keep our eye on for the remainder of 2017. In this video from Summit Safety Group, owner Jake Wolfenden addresses the assumption that President Trump was going to shrink OSHA considerably. The fact remains that he has not, and new regulations are still moving forward. This video gives some insight into what is out there now and what is on the table for 2017–18.

Helicopter Investor | 11 July 2017

Norway and UK Lift Super Puma Ban

The flight ban imposed on the Airbus H225 and AS332 L2 in Norway and the UK has been lifted by their respective civil aviation regulators.

The two Super Puma helicopters will be able to fly again if operators meet revised safety measures issued by the two authorities.

Following a fatal crash of an Airbus H225 in Norway on 29 April 2016, the Norwegian authorities grounded the aircraft. A ban was issued by the European Aviation Safety Agency later in June.

While the European ban was lifted, the H225 remained grounded in Norway and the UK until “further enhancements were made.”

As a result, modifications were made to the helicopter and its maintenance, including removing components susceptible to premature deterioration, earlier component replacement standards, improved maintenance inspection, more frequent inspections, and lower thresholds for rejecting deteriorating components.

John McColl, head of airworthiness at the UK Civil Aviation Authority, said, “This is not a decision we have taken lightly. It has only been made after receiving extensive information from the Norwegian accident investigators and being satisfied with the subsequent changes introduced by Airbus Helicopters through detailed assessment and analysis.”

Read the full story here.

STV | 11 July 2017

BP Will Not Use Super Pumas Until Crash Probe Completed

BP has confirmed it will not reintroduce Super Puma Helicopters until the completion of an investigation into last year’s fatal crash.

Super Puma. Credit: CHC.

The helicopters have been grounded since 13 people, including oil worker Iain Stuart from Aberdeenshire, died in a crash over Norway in April 2016 but have recently been cleared to return to the sky.

The incident off the island of Turoy was the third fatal crash in the North Sea involving a Super Puma since 2009.

The Super Puma ban was lifted by the European Aviation Safety Agency in October, but the helicopters were kept grounded in the UK and Norway.

Last week, plans were outlined by the UK Civil Authority and Norwegian authorities to allow them to return to service if new safety conditions are met.

A survey of 2,500 offshore workers found nine out of 10 were against their return and 65% said they would refuse to fly in one.

Read the full story here.

Siemens | 30 June 2017

Reduce the Risks of Tank Gauging by Using Work Practice Control

Manual tank gauging is a common oilfield activity that has resulted in multiple worker deaths in recent years. By using work practice control, operators can reduce the risks it poses significantly.

Every year, in survey after survey, oil and gas producers cite environmental health and safety as their No. 1 priority. Many, however, continue to perform routine oilfield tasks that can be  improved significantly by employing available technology.

Manual tank gauging is a labor-intensive process that requires a worker to travel to a production tank, climb a ladder to the top, open a hatch, and drop one end of a tape measure down to check liquid level. Vapors released can affect eyes, lungs, and the central nervous system.

In addition to dramatically improving worker safety, automatic tank gauging using radar level measurement technology has a number of advantages:

  • Cost/labor savings
  • Improved accuracy
  • Reduced emissions
  • Enhanced visibility

Read the full story here (PDF).

EHS Today | 19 June 2017

No Worker Left Behind: Protecting Lone Workers in the Oil and Gas Industry

With oil prices gradually rising in recent weeks, oil production sites that were shuttered during the industry downturn finally are gearing up again for operation, perhaps marking an end to an extended slump in the oil market. As oil companies react to these improving conditions, more remote workers will be driving hundreds of miles weekly on back roads in rural areas to work on compressor stations, pipelines, and pump jacks. It is a fact of life for thousands of workers in the oil and gas industry.

Credit: Honeywell Industrial Safety.

These workers also present a challenge for their employers. On the job, they face a host of occupational hazards such as slips and falls, electrocution, falling objects, cuts and burns, and toxic and flammable gas exposure, any of which could seriously injure or kill them. Because they work remotely, it is difficult for employers to monitor their safety and take appropriate action if necessary.

Cloud-based computing and wireless, mobile technology have created a new era of safety for lone workers, going beyond current safety standards. With today’s connected technology, safety managers now can receive a constant stream of real-time data on a lone worker’s exact location as well as their biophysical and atmospheric conditions, and can monitor their safety and initiate or assist with decisive or preemptive safety actions like never before, from anywhere in the world.

Being “out of sight” and even potentially “out of touch” places remote lone workers at risks beyond those faced by their work-based colleagues—even when remote workers are armed with added personal safety measures.

Read the full story here.

Houston Chronicle | 19 June 2017

New GE Startup Tests Drones for Pipeline, Gas Flare Inspections

General Electric has launched a subsidiary to develop and sell the use of flying, crawling, and swimming drones for inspections in the oil and gas industry, among others, the company announced.

A photo of of oil and gas piping taken by a GE drone. The blue color represents corrosion detection. Credit: GE, Avitas Systems.

The startup, Boston-based Avitas Systems, is already working with customers to test the drones on pipelines, gas flares, and holding tanks.

“Now I can send a drone, on demand, and look at the length of the pipeline,” said Kishore Sundararajan, chief technology officer at GE Oil and Gas. He helped start Avitas.

The oil and gas industry has regularly been upended by technology over the last decade. Breakthroughs in horizontal drilling and hydraulic fracturing brought on the shale revolution. The 3-year-old crash in oil prices drove oil and gas companies to lay off workers and rely on newer technologies such as remote monitoring, electronic drill-bit steering, and hydraulic fracturing advances to increase production and lower costs.

Read the full story here.

Shanda Consult via Mondaq | 14 June 2017

Draeger Safety Looking To Expand Its Market in Iran Oil and Gas Industry

Draeger Safety is seeking to expand its market share in Iran’s petroleum industry.

According to Draeger’s regional manager for oil, gas, and chemical, Ian White, its business in Iran is to provide safety products, including protection equipment such as breathing apparatuses, respiratory protection, and face masks to protect people in potentially toxic and poisonous environments. Also, it produces detection equipment that will detect anything explosive in oil, gas, chemical, and petrochemical industries.

Draeger Safety has been developing advanced technical devices and solutions trusted by users all over the world. Its broad range of products, including safety and protection systems, respiratory protective equipment, air filters, detection technology, and warning systems are used in hospitals, for firefighting, for mining, in the oil and gas industry, and in the chemical industry.

In industrial spaces, detection and protection devices are essential part of safety systems. Draeger has combined both detection and protection products, to make sure people are safe before and after toxic gases detection.

Read the full story here.

Colorado Public Radio | 7 June 2017

New Study Looks at Frequency of Oil and Gas Explosions in Colorado

Colorado Gov. John Hickenlooper recently said the home explosion in Firestone, Colorado, that killed two people was a “freak accident.” But a new study by the Colorado School of Public Health indicates that accidents like this may not be so uncommon.

A home in Weld County, Colorado, with an oil drilling rig nearby. Credit: Grace Hood/CPR News.

“What I would tell people is read your deed carefully and be aware of what’s going on around you,” said John Adgate about the need for families moving into areas with oil and gas developments to do due diligence. “What happened in Firestone had to do with a flow line being cut and that, I don’t know the frequency of that happening. As the governor said, he considered it a freak accident. My message would be that accidents happen and we need to manage the risks as best we can.”

Adgate chairs the Department of Environmental and Occupational Health at the School of Public Health, located at the University of Colorado Anschutz School of Medicine. He was a coauthor of the study.

Published in the July issue of the journal Energy Research and Social Sciences, the report says there were at least 116 fires and explosions at oil and gas operations in the state in a 10-year period between 2006 and 2015. With about 53,000 active oil and gas wells in Colorado, that comes out to about 0.03 reported incidents over the course of the study. Adgate says, however, there are questions about the reporting that takes place.

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BSEE | 1 June 2017

President Proposes USD 204.9 Million in Budget for BSEE

President Donald Trump proposed a USD 204.9 million Fiscal Year (FY) 2018 budget for the Bureau of Safety and Environmental Enforcement (BSEE). The budget ensures continued support of the offshore energy industry’s safe and responsible operations providing for secure and reliable energy production for America’s future. BSEE fosters safe and environmentally responsible energy production on the US Outer Continental Shelf through regulatory oversight of oil and gas operations.

The FY 2018 budget request is USD 204.9 million, a USD 600,000 increase above the FY 2017 level, and includes USD 112.0 million in current appropriations and USD 92.9 million in revenue from rental receipts, cost recoveries, and inspection fees.

“President Trump promised the American people he would cut wasteful spending and make the government work for the taxpayer again, and that’s exactly what this budget does,” said US Secretary of the Interior Ryan Zinke. “Working carefully with the President, we identified areas where we could reduce spending and also areas for investment, such as addressing the maintenance backlog in our National Parks and increasing domestic energy production on federal lands. The budget also allows the department to return to the traditional principles of multiple-use management to include both responsible natural resource development and conservation of special places. Being from the west, I’ve seen how years of bloated bureaucracy and D.C.-centric policies hurt our rural communities. The president’s budget saves taxpayers by focusing program spending, shrinking bureaucracy, and empowering the front lines.”

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