Application of Real-Time Monitoring of Offshore Oil and Gas Operations: Workshop Report (2015)

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21 2 Summary of Workshop Discussions Richard Sears, Stanford University (Chair) Susan Dwarnick, Bureau of Safety and Environmental Enforcement Darryl Fett, Total E&P USA Barry Gaston, Shell Joseph Leimkuhler, LLOG Exploration Lisa Grant, Noble Energy Steven Kendrick, BHP Billiton Dale Bradford, Murphy Oil Corporation Anil Wadhwa, Baker Hughes Kevin Goy, Schlumberger Andreas Sadlier, Halliburton Chuck Salminen, Weatherford Lee Geiser, Petrolink Eric van Oort, Genesis Real-Time Systems David Stevens, Chevron Chris Hall, Marathon Oil Steve Bodden, Stone Energy Amro Hamza, Anadarko Tom Moroney, Shell Harris Reynolds, Diamond Offshore Drilling Jean-Paul Buisine, Transocean Offshore Deepwater Drilling Tony Hogg, Pacific Drilling Brian Wright, CAD Control Systems Daniel Marquez, Athens Group Holly Hopkins, American Petroleum Institute Evan Zimmerman, Offshore Operators Committee Alan Spackman, International Association of Drilling Contractors Anton du Preez, National Ocean Industries Association In his opening remarks, Richard Sears, Chairman of the Committee on the Application of Real-Time Monitoring of Offshore Oil and Gas Operations, discussed the context of the committee’s study, the workshop, and the committee’s statement of task, and reviewed the workshop’s agenda. The remainder of the chapter summarizes the presentations and discussions that occurred over the 2 days of the workshop.1 1 Copies of all presentations can be found at the workshop’s website, http://www.trb.org/PolicyStudies/WORKSHOP.aspx.

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 22 OVERALL IMPORTANCE OF REAL-TIME MONITORING FOR BSEE Susan Dwarnick In explaining the importance of real-time monitoring (RTM) to the Bureau of Safety and Environmental Enforcement (BSEE), Susan Dwarnick acknowledged that BSEE is seeking to understand what RTM looks like from the perspective of a regulator, but that it is working with industry to identify the best available and safest technologies. BSEE is introducing several new initiatives, including • A reporting program that captures information about incident near-misses and trends and then returns that information to the industry, • A program that identifies and manages the life cycle of critical equipment, and • An inspection program that will identify facilities on the basis of risk criteria. Third-party verifications and certifications are requirements of the existing Safety and Environmental Management Systems (SEMS) program, as well as the new proposed blowout preventer (BOP) rule, which was released on April 17, 2015. Additionally, she thought that BSEE should evaluate the use of third-party certifications instead of physically witnessing BOP tests at offshore installations. Compliance inspections, which Dwarnick identified as the core mission of the agency, are required once a year, but BSEE is constrained by the number of available technical staff and elevated costs for helicopters. BSEE is responsible for more than 3,000 facilities that are managed by small and large operators and are located from 3 miles to 125 miles offshore. The challenge for BSEE is to determine effective alternatives that focus on risk-based inspections, rather than sending inspectors to each facility every year. The new proposed BOP rule incorporates several industry standards. It would require operators to gather and monitor specific components of real-time data (RTD) independently, automatically, and while continuously utilizing an onshore facility. Dwarnick emphasized that the new proposed rule does not define a role for BSEE, although the agency does reserve the right to access the data at any time. DRILLING OPERATIONS Total E&P USA Darryl Fett A large operator with worldwide assets, Total E&P USA uses limited onshore RTM for drilling and completion activities when collaborative efforts or support may warrant onshore assessments. Total does not routinely use remote RTM operations, even though this well information is available to onshore personnel from contractors over the Internet. Fett reported that Total does not intend to replicate well control monitoring onshore and that all responsibility should stay on the rig. According to

23 Fett, Total supports the use of technology that would allow the outsourcing of certain noncritical tasks—those related to administrative or reporting functions. Such use could provide a benefit by allowing rig personnel to focus on more critical work. Total’s Norway affiliate has the most experience with remote operation centers, where the emphasis is on information availability and collaborative decision making, and is considering expanding its use to include drilling engineering simulations. Fett reported that Total is planning a pilot, real-time support center in France for a 6-month period; the center would not be open 24 hours a day, 7 days a week (24/7) and it would focus on “support” more than monitoring. Fett noted that specific criteria or risk thresholds for RTM requirements have not been specified and that industry use of automation and predictive software is still evolving. Total is considering the use of automation and predictive software for the center in Norway and for the pilot program in France, focusing mostly on drilling efficiencies, but such technology is not currently in place. As for condition- based monitoring (CBM), Fett indicated that Total could consider the wellbore and associated operations as the equipment being monitored and then use available tools to deliver reliable information for assessing trends; however, industry is still determining how best to use RTM technologies in drilling operations. Fett stated that the health, safety, and environmental (HSE) benefits of remote RTM centers have not been established. Fett stated that BSEE could benefit by using the real-time infrastructure to move some “administrative/IT” [information technology] tasks onshore, so that site inspections could focus more on actual observations, and less on the “paperwork.” Additionally, he believes that industry would prefer performance-based requirements over prescriptive requirements and that BSEE should ensure that any regulatory requirements are supported by data and experience. Fett encouraged BSEE to continue working closely with industry to find ways to leverage new technologies, allowing the technologies to evolve and to be built into organizations and cultures (evolution vs. revolution). Shell Barry Gaston Shell, a large operator, has used remote RTM since 2002, first in New Orleans, Louisiana, and then at a second center in Houston, Texas, that started in 2006, after Hurricane Katrina knocked out its New Orleans center. Shell’s RTM is centered on drilling, focusing on well control for its deepwater wells—watching all real-time fluid monitoring data, such as pit volumes, mud weight, flow in, and flow out. For deepwater drilling, monitoring includes plug and abandon operations for surface parameters and workovers that involve drill pipe operations, but not for coiled tubing operations. For completions, Shell streams data into the RTM center for quality assurance and control, and then forwards data to Shell’s completions engineering teams. SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 24 Gaston stated that RTM automation in drilling is still in its infancy, but that Shell does use some predictive software related to connection-flow monitoring and a heat- check calculator for casing wear. The use of predictive software supplements what is done on the rig; it does not replace it. According to Gaston, Shell does not see a direct connection between CBM and drilling operations. Although it could be used for the monitoring of surface equipment, Gaston believes that CBM is not mature enough to play a role in downhole operations. He does think that CBM has greater benefits for production operations, for items such as engines and pumps that could be monitored continuously for the longer term. Like other operators, Gaston encouraged BSEE to visit Shell’s RTM center to view the data from the rigs, which would help to provide context and situational awareness. Although it provides another “set of eyes,” RTM could not replace any activities on the rig. For Shell, the biggest benefit of RTM has been providing timely data to identify proactively equipment that is out of calibration or failing. Also, historical data provide a repository for possible incident investigations. RTM may lead to a reduction in on-site visits for BSEE for items that could be monitored remotely, such as BOP testing, but BSEE would still need sufficient staff to carry out such tests. LLOG Exploration Joseph Leimkuhler LLOG Exploration is a private company operating as an independent operator in the Gulf of Mexico. Although it does not have a physical center, LLOG does use RTM beyond its on-site rig supervision, streaming the data virtually into the office and allowing onshore engineers the capability of monitoring critical parameters on all of the company’s deepwater wells. For LLOG, monitoring the drilling of exploration or development wells where the pore pressure and fracture gradient trends are not well understood is a valuable example of RTM. LLOG ensures that RTM capability is in place for all of its deepwater drilling operations, both exploration and development. Downhole well operations are not conducted in a controlled environment and rely on estimated parameters within a range of assumed values. Any use of automation or predictive software would likely lead to false alarms and loss of confidence in the system. Leimkuhler stated that BOP systems, updated to allow streamed critical parameter data, could be monitored because these systems are more mechanical and not reliant on downhole systems. This type of monitoring could add value if actions are consistent and responsive. However, Leimkuhler noted that this equipment is owned and maintained by the drilling contractor, and that any CBM would have to interface with the drilling contractor’s data acquisition system. The use of these data for possible intervention decision making would have to meet the drilling contractor’s

25 SUMMARY OF WORKSHOP DISCUSSIONS and the original equipment manufacturer’s (OEM) data quality assurance and control standards, as well as work within the drilling contractor’s SEMS program. Any intervention protocol would have to be approved by the operator via the operator’s and drilling contractor’s SEMS bridging documents. Leimkuhler further noted that RTM of data by BSEE should not replace any on- site inspection programs, although such monitoring could supplement BOP pressure tests once remote monitoring of these tests is proved to be reliable. Also, a properly archived RTM data stream could enhance BSEE’s on-site inspections and incident investigations by providing a common data set. While BSEE inspectors are on a rig, Leimkuhler stated, they spend a lot of time going over paperwork and documentation. By reviewing the paperwork before arriving on site, the inspector could spend more time examining equipment and observing operations. Leimkuhler added that any new regulation should be performance-based and should not require a fixed structure, building, or office to house the RTM capability. Instead, the operator should be allowed to document how the data stream is (a) accessed in real time, (b) archived, and (c) accessed for use by the operator and contractors on a real-time and post-event basis to enable safe operations. Noble Energy Lisa Grant Noble Energy’s response model empowers the people on the rig, where the expertise is located, to make decisions. In case of a well control or process safety event, the rig team can act quickly. Noble’s use of shore-based RTD monitoring assists the rig team, but does not take over the operation. An independent operator, Noble does not have a dedicated remote RTM center, and its use of RTD is not on a 24/7 basis. Noble does target high-risk or extremely complex operations for remote RTM—examples include jetting operations, critical formation integrity test operations, and pore pressure estimation—when it may want a second “pair of eyes” for collaborating with the rig team. Noble does not monitor a standard set of parameters and does not believe that all wells should be monitored. Because it has limited resources, Noble reviews each well to determine—on the basis of risk—if monitoring will benefit the operation. Predictive software could be used to determine baseline trends and to flag deviations; examples include torque and drag modeling, equivalent circulating density (ECD) prediction, pore pressure prediction, and pressure profiles of production functions. But models are only as good as the data that go into them. Automation is not a viable option until sensor data and related processes are reliable and consistent, without a significant number of false alarms.

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 26 CBM could be used for preventive maintenance of equipment, where RTD- driven algorithms are used to create notifications on the basis of usage and estimated wear and tear instead of predetermined scheduled time intervals. Examples could include monitoring actual ton-miles for slip and cut procedures, BOP actuations and utilization for rubber-goods replacement, casing tests scheduled on the basis of anticipated wear as a function of rotating and tripping hours, and monitoring annular pressure buildup changes in production wells. Grant suggested that BSEE monitor simple systems and fundamental safety systems to ensure compliance, such as BOP testing, purge alarms, and gas detectors. Although the remote monitoring of downhole data can be subjective and impede situational awareness of what is happening on a rig, BSEE could use RTM to supplement its compliance enforcement through such items as checking the frequency of BOP test results and BOP testing and functioning, as well as the frequency of casing test results. Another suggestion is that BSEE establish key performance indicators (KPIs), along with incidents of noncompliance (INCs), to help perform trend analysis and to understand compliance, and maybe even to discourage noncompliance between inspections. In addition to monitoring simple safety systems to ensure compliance, Grant suggested, BSEE should provide guidelines for sensor accuracy and precision and guidelines on communication protocols for data transfers. However, new measures should not replace BSEE inspections on the rigs. BHP Billiton Steven Kendrick An independent operator, BHP Billiton (BHPB) has RTM capabilities, and RTD are accessible to drilling and completions teams, including third-party vendors; however, BHPB does not staff a remote 24/7 RTD center. BHPB does have a room set up in its Houston, Texas, office where onshore personnel can remotely review operational data for drilling and completions and can communicate and collaborate with rig personnel. BHPB requires continuous monitoring of well-control data by rig personnel—BHPB and third-party personnel—but the company does not require remote RTM. BHPB does not use automated or predictive software for drilling operations, although alarms are used on the rig to call attention to data that have left an expected range and should be reviewed. If automated or predictive tools are designed, they would be best suited for on-site use, because situational awareness of the rig is important. Some predictive software is used during well planning to indicate what to expect during operations, such as torque and drag and required pump pressure at different pump rates. When the data begin to deviate from planned parameters, rig personnel are likely to seek assistance from onshore.

27 The newer generation of rigs allows equipment manufacturers to log in remotely for troubleshooting and support of BOPs and some critical rig systems. Kendrick added that operators should investigate any additional functionality offered by equipment manufacturers. Although it would not be in real time, BSEE could use archived data to understand issues, to verify information on International Association of Drilling Contractors reports, or to help in incident investigations. For BHPB, archived data goes back more than 12 years. BSEE could use RTM to supplement the monitoring of BOP test pressure and the reviewing of pressure test charts, but it should not replace on-site inspections because of the importance of BSEE’s physical inspection of the rig. Even with RTD available, BSEE would have a difficult time deciphering the data without full situational awareness of rig operations. Another suggestion from Kendrick was that BSEE could require the use of RTM for well-construction decisions and troubleshooting and for supporting rig personnel in making well-safety decisions. This type of requirement would not necessitate a center that was staffed 24/7. Murphy Oil Dale Bradford Murphy Oil is an independent exploration and production company that uses RTM for offshore operations and for improving information exchange between rig personnel and non-rig personnel. RTM technologies allow data streams to be recorded and available continuously; however, the data are viewed and analyzed by a wide variety of support personnel on a continual basis. Murphy’s operational and business models do not support a requirement for a dedicated remote RTM center with 24/7 staffing. In the event of a major well-control or well-containment incident, Murphy can access a 24/7 RTM center as a member of the Helix Well Control Group. According to Bradford, Murphy monitors most available drilling data streams, including such drilling parameters as pit volume totalizer, weight on bit, rotations per minute, torque, flow in and flow out, rate of penetration, and equivalent circulating density and formation evaluation parameters such as resistivity, gamma ray, density- neutron, and gas levels. For exploration wells, Bradford reported that Murphy monitors real-time pore pressure and pressure-to-fracture gradient window analysis; for some development wells, Murphy uses the RTM center provided by the contractor. Drilling contractors and service companies employed by Murphy also collect and use data, although it may be for different purposes. For example, these contractors may be more interested in equipment performance and will monitor BOP controls and status, equipment condition, maintenance status, and other parameters from the contractors’ facilities. Murphy is more interested in how equipment performance may impact the SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 28 overall drilling performance. For Murphy, any decision to use RTM is driven by the business case. For offshore drilling, and for some onshore drilling operations, a sound business case does exist for targeted, continual monitoring; however, Murphy does not believe that a sound business case exists for a 24/7 continuous monitoring center. Generally, Murphy does not use automation and predictive software in its operations, although limited predicted software is used for pore pressure and mud window analysis on certain wells. Bradford stated that in Murphy’s view, the downhole environment is highly variable; any use of automation and predictive software should be limited because existing technology may be insufficient to accomplish the task and data streams may be unreliable. Any excessive reliance on automation, remote tools, or remote monitoring could undermine rig authority and lead to distractions and misinformation. Bradford stated that drilling contractors are currently using CBM for their engines, dynamic positioning (DP) systems, BOPs, and other critical equipment, with some contractors having remote access and troubleshooting capability. Contractor and OEM personnel have the expertise to use CBM to manage the performance and safety of their equipment, but Bradford does not believe that BSEE has the necessary staff experience to leverage this technology. Bradford believes that BSEE could use remote RTM for BOP witness testing that supplements on-site witness testing and that contractors could modify software to allow access to the data. Potential issues with remote witnessing include the accurate recording of valve positions, the remote understanding of test results, and access to and security of the data. Current BSEE inspections of offshore facilities involve data collection and data review. Bradford suggested that there could be value in making these data available remotely or prior to the inspection, so that the inspector can target specific areas or spend more time onboard talking to the rig personnel to determine overall competence, which is the real importance of on-site inspections. He also suggested that BSEE abstain from prescriptive rulemaking RTM protocols. Many offshore operators, contractors and service companies use a wide range of data streams on a continual basis, with each company having a different business case for using RTM. He added that the industry could do a better job of improving how the data are collected, integrated, and stored. Discussion During the discussion, the committee asked whether any direct benefit to HSE exists from the use of a remote RTM center, either from the technology or from established processes. For Shell’s Gaston, the direct benefits to HSE are difficult to quantify, but one benefit is better team integration and better data quality. Several panelists stressed that RTM provides a lot of value in efficiency and saving money in well planning, and in the ability to recreate and understand events, but that from an HSE perspective,

SUMMARY OF WORKSHOP DISCUSSIONS remote monitoring has not caught an event before rig personnel have. Additionally, an important point of after-the-fact reviews of drilling operations is that a lot of those data were not necessarily being streamed off the rig in real time, but were only being stored on the rig. Data are definitely useful after the fact, and many of the panelists noted that their companies collect, aggregate, and archive data from multiple sources for this purpose. When asked about the proposed BOP rule and monitoring all control aspects of the BOP system, many panelists agreed that the BOP is something that could be monitored, because it remains in a relatively static state most of the time. The BOP is close to an independent system that is isolated from the influence of the wellbore. However, LLOG’s Leimkuhler would refer to the drilling contractor and BOP owner for advice on how to manage the monitoring of the actual parameters and the data stream from the BOP. Similarly, Fett stated that Total does not perform a lot of BOP monitoring, relying on the drilling contractor, but he declared that the BOP is part of a larger system and that Total, as an operator, is ultimately responsible for interfacing with the contractors and for managing all the associated risk. Gaston added that Shell does remotely monitor BOP tests and could stream all data into its office, but the ability to monitor the whole system on a continual basis is in an early state. From the discussion, operators employ different models of RTM. The panelists reported that many companies would require a business case to justify the use of RTM or support building a dedicated remote monitoring center. Many panelists agreed that there is value in collecting and aggregating the different streams of data, but the value lies more in improving operational efficiencies than in well control. When asked about the time needed to start an onshore remote monitoring capability, LLOG Exploration’s Leimkuhler responded that the initial setup of the information stream and screens can take place within a week. As far as developing trust and confidence in someone who is looking over your shoulder at the data, the time needed could be about 6 to 8 months. That period could be shorter if the interaction were to take place offshore on the rig, rather than in an onshore–offshore collaboration. The amount of involvement or interfacing that operators have with contractors’ monitoring of equipment varies between organizations. Operators rely on contractors to monitor and maintain their equipment in a safe manner, but operators will serve as facilitators in order to make proper risk decisions. Drilling contractors and operators use RTD in different ways, often to accomplish similar objectives. According to several panelists, the bridging or well construction interface documents establish that well control maintenance and equipment are the contractor’s responsibility, but usually do not go into explicit detail about the different uses of data. Operators do use third-party auditors to review maintenance and control systems. 29

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS THIRD-PARTY RTM PROVIDERS Anil Wadhwa As part of a combined presentation, Anil Wadhwa of Baker Hughes started this panel session by providing answers to questions where general agreement existed among the panelists. From the perspective of third-party providers, real-time well monitoring involves the acquisition and aggregation of sensor data that are transmitted in a secure format to a data center where the data are processed before being made available to the end user. The main role of the third-party provider is to gather well data on behalf of its client, usually the operator, and then deliver the data to subject-matter experts; all decision making and all accountability belong to and remain with the operator. The service companies do use some level of automation and remote control, mainly for performance assurances and operational efficiency of equipment. The panelists who spoke agreed that RTM can supplement decision support for field operations through alarms and alerts, knowledge management, and data interpretation, and can also help with the predictive and preventive maintenance of safety equipment. Schlumberger Kevin Goy Schlumberger, a large solutions and services provider, generally uses RTM information for performance assurance. To Schlumberger, real-time centers allow a collaborative approach to support operations by providing access to a global network of expertise, consistent situational awareness, and improved communications across all stakeholders. According to Goy, Schlumberger does monitor critical operations and uses CBM, especially for sensors on the bottom-hole assembly that provide shock and vibration information; the principal focus is on reducing nonproductive downtime. Schlumberger’s five key lessons from running a RTM center include the importance of • Developing companywide standards (e.g., RTM hardware, data security, and key performance indicators); • Formalizing industrialized workflow for improved oversight and chain of command (i.e., who does what and when); • Understanding your personnel, knowing their expertise, and having the right people in the right places; • Having escalation and communication protocols established prior to the start of a job; and • Using appropriate advanced monitoring tools. 30

Halliburton Andreas Sadlier Halliburton, also a large solutions provider, offers services and information at the direction of the operator or customer for improved operational decision making. For Halliburton, automation is limited to alarms and alerts in an effort to improve data quality (assurance and control), but potentially also workflows and decision making. Halliburton does not use predictive software. The company bases protocols and the chain of command on best practices and on the contract and service documents that are defined prior to the job start. Like the other panelists, Halliburton does typically monitor critical operations and parameters and uses CBM for downhole tools and equipment performance. According to Sadlier, RTM is a great training tool that allows someone to be exposed to various types of operations without having to travel to the various sites. Sadlier believes that, to incorporate RTM technologies into BSEE’s existing regulations, BSEE will have to understand the many different workflows and protocols and the different types of expertise needed for this technology. More important, BSEE must understand the challenges of collecting, distributing, managing, and securing the data. Weatherford Chuck Salminen Weatherford, a large solutions and services provider, supplies RTM data and key information to rig personnel for decision making. Although it is mainly used for optimizing performance, RTM can help manage costs and avoid potential hazards. Data security is important; a well-established and auditable communications trail should exist between the remote center and the rig site. Although most communication protocols between onshore and offshore personnel exist on a client- by-client, project-specific basis, the rig always maintains authority. As for critical operations and parameters, Salminen stated that Weatherford would prefer to monitor anything that has the potential of generating a critical safety event. If a remote RTM center will be asked to provide the same level of insight as if it were on the rig, then all rig data should be transmitted to the remote center; the scope should not be limited. For many of these critical sensors (e.g., pit levels, total gas, flow, casing pressure, and choke and kill line pressures), redundancy is important. Depending on the definition of “predictive,” Salminen stated, Weatherford uses predictive software for such things as hydraulics, kick, torque and drag, and wellbore stability. At the well site, the rotary steerable tool does have some automated capability in setting a path and maintaining a heading. Weatherford has the capability, with managed pressure drilling systems, to do automated kick and loss detection and 31 SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS control at the rig site, but this is not something that they would want to do remotely. CBM is used to track the health and performance of equipment, both surface and downhole; this helps with preventive maintenance. Petrolink Lee Geiser Petrolink is a vendor-neutral service company, meaning that it does not have sensors at a rig site. Petrolink works under contract for operators, who provide the data standards to be followed by Petrolink in acquiring data, aggregating and integrating data, and then processing and analyzing data. The role is to ensure that all the data that are produced at the well are captured and delivered; the data then become the property of the operating company. Petrolink can create alarms and alerts on the basis of parameters identified by the operator. Standardization of data formats and content could improve the efficiency of this task. University of Texas at Austin Eric van Oort Third-party providers collaborate with operators and offer enabling tools, processes, and subject matter experts that help operators achieve operational excellence (in both performance and safety) in onshore and offshore well construction. Operational decision making and accountability should always reside with the operator, although contractors should be accountable for the quality and accuracy of information they provide. The chain of command and communication protocols should be tailored to the operator’s existing structure. Critical operations for operators include pressures, loads and torque, volumes, flow rates, temperatures, and operational readiness of equipment. Van Oort suggested that regulators could monitor parameters associated with regulatory compliance and with the prevention of catastrophic events, such as blowouts and spills, but not monitor the day-to-day drilling operations and performance management. His presentation included historical data showing that the contributing factors for most U.S. blowouts between 1992 and 2006 were casing and cement evaluations, followed by drilling-event detection and BOP reliability verification. CBM of critical equipment could play a role in areas such as monitoring top drives, mud and cement pumps, and BOP operation, as well as the regulatory information required by the operator, such as BOP tests, casing and shoe tests, and production casing high and low tests. All of this would require subject matter expertise, reliable input data, and state-of-the-art modeling algorithms to minimize false positives. To leverage RTM technologies, van Oort believes that BSEE could 32

build collaborative relationships and learn from experienced operators. He also suggested that BSEE could focus on events that have historically caused blowouts, and consider vendor-neutral IT infrastructure and commercial-off-the-shelf (COTS) solutions. Panel Summary Before opening the discussion, Anil Wadhwa of Baker Hughes summarized several repeated themes heard during the presentations: • Although full-time remote RTM centers are possible and can support field operations, there is a cost. • The ultimate responsibility for operations should remain with the rig and well personnel. • Data generated from the rig belong to the operators. • Despite technological advancements, reliable service is not 100% guaranteed. • Cybersecurity issues and the use of mobile devices to display information have added additional risk to cloud-based services. Discussion and Observations Many panelists noted that remote monitoring centers (and technology) do not detect issues or well-control events before rig personnel do. The RTM centers of the service companies are looking primarily at equipment performance and trends and do not monitor well control. One panelist observed that remote centers complement the rig and that any interventions are specific to the provider’s own equipment; to clarify, there is no “big red button” inside the operations center to shut everything down. However, van Oort stated that, while working at Shell, he had seen red-flag interventions from the center that averted a well-control event. Many on the panel agreed that data latency is a lesser issue; there is more bandwidth to and from offshore than there was 5 years ago. Available information technology and data flows are evolving rapidly and current top-end solutions are likely to become obsolete within 5 years. Several panelists suggest that regulating in this environment is difficult and flexibility should be built in. Regulations for monitoring centers designed around today’s technologies are also likely to become obsolete within 5 years. Each operator has its own data requirements when interfacing with multiple contractors. Although standards do exist, several panelists stated that the standards are not always followed. Overall, many of the panelists suggested that the industry should agree on standards in order to exchange data faster. However, there is no real agreement across operators about what data they want to receive and how they want 33 SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS to receive those data. Determining critical information may be essential in moving forward, but the panelists also suggest that industry needs to provide better or more reliable data, not just more data. John Cushing of BSEE noted that the day’s presentations and industry feedback validate many of the findings of the Summary of BSEE’s Real-Time Monitoring Study (BSEE 2014). The oil and gas industry uses a wide range of RTM technologies and a standard approach clearly does not fit everyone. Situational awareness is important, and viewing data without the situational context can be misleading. Cushing suggested that the bigger question surrounding RTM technology could be about drilling safety and the roles of the industry and the regulator concerning drilling safety. PRODUCTION OPERATIONS Chevron David Stevens As a large operator, Chevron’s decision to use RTM for production operations, which are largely steady state in nature, is driven by business need—primarily for production optimization, efficiency, and reliability. The company uses RTM to monitor, diagnose, and troubleshoot rotating equipment. Chevron’s goal is to limit downtime, but Stevens does not believe that specific types of wells or operations and parameters should always be monitored. Chevron does not monitor its production facilities on a 24/7 basis and does not use RTM as a safeguard for personal safety or for process safety. According to Stevens, Chevron uses predictive tools for leading indicators on rotating equipment and reservoir production management, and the company has seen tremendous benefit using CBM—or what Chevron considers RTM—for rotating equipment performance and reservoir management. Chevron’s Stevens believes that BSEE should explain its intent better, or should define its objective for requiring the use of RTM technologies for anything beyond industry’s current practice of using it for optimization, efficiency, and reliability. Marathon Chris Hall Marathon is an independent operator that has some capabilities for monitoring remote operations, but these capabilities have only been used for hurricane evacuation. Information is transmitted to an onshore facility that has the functionality to replicate what offshore personnel can view, but the facility is not staffed 24/7. More often, RTM is used for remote diagnostic support of on-rig processes. The data could be used for earlier detection and notification of machinery failures. 34

CBM, along with predictive software, could provide the ability to schedule maintenance and proactive response to equipment failure. CBM is important elsewhere around the world, but Marathon does not use it in Gulf of Mexico operations because of aged technology and the limited bandwidth of current Gulf installations. Hall suggested that data could be published to a browser-accessible Internet facility that provides BSEE with the capability of viewing or archiving specific data as needed. Because the data provided would not be digested in real time, Marathon, according to Hall, considers such efforts by operators to be not entirely useful. Although technology could reduce the number of trips that BSEE inspectors would have to make to offshore facilities, RTM should not preclude or replace on-site inspections. Also, questions remain as to whether BSEE would be able to hire an adequate number of subject matter experts for any proposed RTM operation. Hall noted that operators already enter some production data to an external website, but visiting BSEE inspectors may not be effectively viewing or using these data on a regular basis. BSEE’s use of RTM technologies could be constrained by such issues as cybersecurity and companies’ unwillingness to share all data. Additional constraints on BSEE’s use of RTM include issues of intellectual property rights, weather and bandwidth limitations, and perceived and actual safety gains. Also, many facilities in the Gulf of Mexico are older and not equipped to facilitate RTM. What are the costs and the unintended consequences that could appear if RTM were required on all facilities? At the end of the day, Marathon’s Hall believes that on-site inspections by BSEE are still needed. Stone Energy Steve Bodden As an independent operator, Stone Energy’s perspective is that all command and control should occur at the offshore facility. RTM has value for viewing operations and providing information for decision making, but the technology is used primarily for surveillance of well information and rotating equipment and for creating trend data. Stone does not have specific criteria for installing RTM capability, but does see a business case for its use in a production field with at least 3 years remaining, justifying the RTM costs for surveillance only. Bodden believes that BSEE could perform parts of the annual inspections on specific platforms via video conference for control room visits, but this does not allow BSEE to assess the physical condition of the facility. Although video conference or control room visits for component testing of safety devices could reduce the number of offshore trips by BSEE inspectors, BSEE should not eliminate on-site inspection visits, which continue to provide considerable value. Bodden recommended that that BSEE not require mandatory upgrades of current pneumatic control systems and electronic control systems. 35 SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS Anadarko Amro Hamza Anadarko is a large independent operator. Its onshore facility in The Woodlands, Texas, is not staffed 24/7, and any maintenance activities are limited to daytime hours. All offshore production facilities maintain responsibility and control. Like the other panelists, Anadarko uses CBM for large rotating equipment to predict possible failure, but this is a response to a business need (to limit down time), not to a safety need. Hamza believes that BSEE should continue with annual inspections and not replace them with RTM. Anadarko performs and records monthly inspections. If BSEE would like to review these inspections, the data are available; however, witnessing inspections on the screen does not add confidence and should not replace annual inspections. RTM is an operational tool used to support offshore staff. As an oversight tool, RTM might not add value and may give offshore personnel a false sense of security. Shell Tom Moroney Like other panelists, Shell has invested in RTM centers for production because a business case exists for them. Shell’s collaboration centers support more than 60 facilities around the world and span the asset’s life cycle. These centers share a common methodology, standardized technical solutions, and a high level of communications that capture lessons learned and allow for rapid sharing of information. The flow of information is important. Shell does use CBM for the surveillance and maintenance of its equipment and sees value in its use. Moroney does not necessarily see a role for BSEE in CBM and does not believe BSEE can leverage a specific technology. Overall, he noted, Shell would rather see BSEE set performance objectives than prescribe RTM rules. Discussion Many of the panelists for production operations stated that RTM facilities send data by satellite and generally do not send video feeds from offshore (other than to and from the control room). For CBM of large rotating equipment, the operators on the panel suggest that this work is well integrated with OEMs or with third-party providers, or both. The operators represented on the panel felt that CBM allows them to intervene with critical equipment information before failure occurs, but this intervention often uses archived data or fleet data and does not necessarily rely on RTD. The general process is to capture data, analyze data, produce trends, and make decisions, but this process is not instantaneous (i.e., real time). 36

During the discussion, some of the panelists were asked to clarify RTM. To many on the panel, RTM is the ability to get information in real time for the operators, who are usually stationed on the rig. Remote RTM provides the same capabilities, but from a remote location. Additionally, the term “remote real-time command-and-control oversight” means that someone (usually at a separate location) contacts an offshore installation and requests that an action take place, either through human intervention or through automation. Many of the panelists responded by saying that although communication and consultation with onshore personnel are encouraged, all decisions are made by the production personnel offshore. DRILLING CONTRACTORS AND EQUIPMENT MANUFACTURERS Harris Reynolds, Jean-Paul Buisine, Tony Hogg, Brian Wright, and Daniel Marquez Harris Reynolds of Diamond Offshore Drilling presented highlights from the discussion of the panel of drilling contractors and equipment manufacturers, while other panelists added remarks as necessary. Drilling contractors perform drilling, completion, and well-test operations for operators using drilling units that they own and operate, normally on a day-rate basis. Although contracted by the operators to perform operations at their direction, drilling contractors are ultimately responsible for the safety of the rig and of all the personnel operating on the rig. On-rig automation is commonplace for activities such as pipe racking and power management and other items where a business case has been made, especially in the area of safety. According to Reynolds, no offshore drilling rig has any process that is automated or controlled remotely from onshore. All command and control is located on the rig. He added that the chain of command on the rig has been well established and that decision making should include the situational awareness of all rig activities. Until there is solid evidence that equipment condition or status can be determined from data alone, Reynolds noted, RTM should continue to be a supporting tool for the existing chain of command on the rig. Adding an additional layer of management does not improve safety. Drilling contractors typically collect and provide all available data to the operators to use at their discretion. Normally, a list of which data an operator requires is written into the contract and the list rarely changes. Some contractors monitor equipment remotely using CBM and preventive maintenance, but this does not necessarily happen in real-time; data are usually archived and analyzed later. Given the right communication infrastructure, personnel onshore have the ability to see what personnel on the rig see, but this ability to transfer data in real time is not on every rig. As for critical operations and parameters that should always be monitored, Reynolds noted that drilling contractors believe that all wells and offshore operations are critical and that they supply all data, as defined in the contract, to the operators. In addition, he highlighted that the U.S. Coast Guard defines critical outer continental 37 SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS shelf activities in 33 CFR 140.305 under new Subpart D, and suggested that federal agencies synchronize divergent standards. BSEE would like to leverage RTM technologies to reduce the number of trips offshore, but several panelists suggest that inspectors would not have full situational awareness unless they are on the rig. Reynolds suggests that any attempt to leverage remote RTM technologies should be prototyped before implementation, for example, by having BSEE inspectors wearing body cameras and microphones during BOP tests. Many of the panelists agreed with others at the workshop that such technologies should supplement, but not replace, inspections. Inspectors could have access to reports on BOP test results and equipment condition before the inspection. This would provide more of an operational perspective, so that inspectors could concentrate more on how the rig is operating as a whole and less on reviewing paperwork. Additional issues and risks of BSEE using remote RTM oversight include the training and experience requirements for onshore personnel and potential legal liability connected with BSEE oversight of drilling operations. Brian Wright of CAD Control Systems discussed cybersecurity concerning industrial control and automation systems that are designed to work in harsh environments and for long life spans. Such a system is tested very thoroughly and is not touched again; historically, remote connectivity and security were not part of the original system design. Applying Windows security patches to industrial control software could have severe repercussions because of potential incompatibility issues. Wright also discussed the issue of the Stuxnet computer worm.2 Many of the panelists agreed that one important step to improve offshore safety is to address the competency of rig personnel through the ISO 17969 Guidelines on Personnel Competency.3 This initiative has not been adopted by the industry but could be an important reference for such a discussion, and should be consider when advancing a requirement for an additional “set of eyes” to review operations from an onshore facility. Another important step involves training and the use of advanced well control simulators that are currently used throughout the drilling industry. Such simulators provide insight into issues faced by subsea engineers and supervisors. Discussion Several panelists stated that remote RTM of the BOP control system is available, and that personnel would have the capability of viewing all the data from the control system that the rig personnel see, but that remote monitoring is not currently being done. They added that the available data include hydraulic pressures, opening and closing pressures, and volumes, for example, but not the actual positions of the BOP rams. The technology to detect ram positioning may be available, but the main 2 An overview of Stuxnet is available at http://spectrum.ieee.org/telecom/security/the-real-story-of-stuxnet/ and https://www .tofinosecurity.com/stuxnet-central. 3 See http://www.iso.org/iso/catalogue_detail.htm?csnumber=61167. 38

issue remains deploying it in harsh subsea operating conditions while still producing reliable results. Until reliability approaches 100%, the danger of a false positive will prevent contractors from adopting the technology. Monitoring of BOP health is something that exists with current technology, mainly to determine how much life is left in the BOP, but BOP health is not monitored in real time or 24/7. Drilling contractors generally want to optimize maintenance practices. TRADE ASSOCIATIONS Holly Hopkins, Evan Zimmerman, Alan Spackman, and Anton du Preez Many of the panelists agreed that remote RTM is used by shore-based personnel as a support tool to improve the efficiency of certain wellsite operations, which may also favorably impact safety and the environment. RTM technology is widely available, but its use is determined by an individual operator’s business case. Some of the panelists suggested that BSEE clarify whether its intent for RTM focuses on safety, on improving oversight and reducing BSEE’s inspection burden, or on BOP health monitoring and forensic investigation. Before determining the probable effects of RTM on the industry, the panelists would like to understand what objective BSEE is trying to achieve or what problem BSEE is trying to solve with RTM requirements. The RTM requirements for drilling operations would be very different from the requirements for production operations, and these requirements are likely to affect the available labor pool for both industry and the regulator. Many of the panelists do not believe RTM should be a regulatory requirement. Some panelists proposed that any new rule be coupled with a clear understanding of what data are required, who will be able to view those data, and how the data will be used. The concern expressed during the presentations is that the access to or transfer of data be structured in such a way that the security of vital equipment and systems is not compromised. One panelist indicated that industry members would need to evaluate possible impacts and modifications to their internal procedures and management systems carefully. The new requirements could introduce uncertainty into the chain of command, have significant impacts on smaller operators, and potentially change competitiveness in the Gulf of Mexico. Additionally, one of the panelists suggested that BSEE clarify how the new requirements would interact with existing regulations on obligations and liabilities of contractors who are performing the activity. A forum for the development of consensus-based industry standards and technical cooperation to improve industry safety performance and competitiveness is provided through the American Petroleum Institute (API). Many of the panelists suggested, however, that development of recommended practices or standards would be premature until the objectives and desired benefits of RTM were better understood. A robust understanding of RTM components that add benefits and produce a positive impact on safety is needed for both industry and regulator. The establishment of 39 SUMMARY OF WORKSHOP DISCUSSIONS

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS common definitions is important because various actors in the industry may have different interpretation of what operations are critical. Trade associations can function as a forum for dialogue and a hub for sharing safety-related values of RTM. One panelist suggested that BSEE can do its part as a regulator to help coordinate information gathering and to cooperate on RTM research. The panelist added that BSEE can act as a conduit for the dialogue in evaluating RTM risks and for identifying unintended consequences of proposed requirements. API has assembled an RTM subgroup that includes more than 120 members, but the ultimate objective of this workgroup is to respond to any potential proposed rulemaking and then be responsive to this committee. According to one of the panelists, the industry does not agree that a best or recommended practice or a standard on RTM is needed, including what elements to consider. As technology advances, RTM will continue to evolve. If regulatory requirements are to remain current and relevant, some of the panelists suggest that BSEE consider performance-based rules to achieve shared goals of responsible operations. Industry’s main concern is trying to understand the perceived problem that BSEE is trying to solve by pursuing RTM requirements. RTM is one tool that could be used to achieve safe and responsible operations. If BSEE could provide a defined problem statement or a design-based type question, then industry could convene the necessary expertise to begin this discussion. ADDITIONAL OBSERVATIONS During the last session, Chair Richard Sears noted that the presentations and discussions from the 2-day workshop expressed many common themes and observations, but he emphasized that the committee is still gathering information and deliberating and is not ready to make any findings, conclusions, or recommendations. Any findings and recommendations will be included in the committee’s final report, which will be released in 2016. Several other participants during the open discussion periods of the workshop did provide comments. Sandi Fury of Chevron appreciated the discussion of RTM at the workshop but noted that the discussion was incomplete. She remarked that the workshop had lacked a discussion on how to drill safely or operate a production platform safely and that RTM is only one of many tools that support safe operations. Additionally, areas of concern, such as data quality and cybersecurity, should be addressed in future forums. She added that there is a willingness on the part of industry to have a discussion about RTM, but that there is a lack of understanding of what problem BSEE is trying to address with these requirements. Acknowledging the importance of these issues and concerns would be necessary for the success of any RTM program. She said she hoped that BSEE will recognize this need before moving forward with this rulemaking. 40

SUMMARY OF WORKSHOP DISCUSSIONS Robert Conachey with the American Bureau of Shipping made observations about BSEE’s possible collection and use of data. His initial concerns centered on the potential legal and immunity issues that could arise when an operator provides data before an event occurs. He also questioned how proprietary technologies would be protected, given the competitiveness of the industry. Additionally, he cautioned that collecting more data after an event—focused on that event—may not be the best plan of action, since that type of event may not ever occur again. He suggested risk-based studies, such as failure mode and effects analysis, as one possible way to understand system functions and to identify failure modes, which, along with condition monitoring techniques, could help determine future maintenance needs. The data analysis could focus on probabilistic rather than deterministic methods. Bill Nelson with Det Norske Veritas Germanischer Lloyd agreed on the importance for industry to identify or clarify the necessary decisions and the information required to make those decisions. He added that identifying the information and decisions is important for the regulator, which could benefit from some sort of common framework for its regulatory decision making. Echoing the concerns of Conachey about collecting more data on previous events that may not happen again, Nelson notes that the nuclear industry faced a similar problem in planning for accidents after the Three Mile Island incident—knowing that severe accidents were possible, but not knowing what they might look like. In addressing this concern, the Nuclear Regulatory Commission developed an approach called Critical Safety Functions for systematically identifying the information needed to manage potential accidents without having to identify every possible scenario.4 REFERENCE Abbreviation BSEE Bureau of Safety and Environmental Enforcement BSEE. 2014. Summary of BSEE’s Real-Time Monitoring Study. U.S. Department of the Interior. http://onlinepubs.trb.org/onlinepubs/sp/Cushing_Summary_of_BSEE_RTM _Study_March_2014.pdf. 4 For more information on Critical Safety Functions, see http://www.ans.org/pubs/journals/nt/a_32814. 41