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

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11 Introduction Chapter 1 gives a brief overview of actions taken in the area of real-time monitoring (RTM) by the Bureau of Safety and Environmental Enforcement (BSEE) since the accident on the Deepwater Horizon drilling rig in 2010. This chapter also provides a brief history of real-time data (RTD) collection and monitoring of oil and gas operations. Next, the chapter briefly summarizes two reports, one by a company called 838, Inc., that provides background material on RTM and available technologies, and one by an internal BSEE workgroup, the Real- Time Monitoring Team, that reviews the potential uses of RTM technologies for both the government and the oil and gas industry. The chapter also reviews two notices of proposed rulemaking issued by BSEE during the planning of the committee’s Houston workshop. BACKGROUND In the aftermath of the Macondo well blowout and Deepwater Horizon rig explosion in April 2010, BSEE1 began searching for the most effective oversight role that it could play in enhancing the safety of offshore oil and gas operations. Immediately after the accident, BSEE carried out a rulemaking process that required operators to implement safety and environmental management systems (SEMS) (TRB 2012). Subsequently, the agency began urging industry to make a deeper commitment to a strong culture of safety in all operations. The agency also sought improvements in implementing its mandate for best available and safest technology (BAST).2 BSEE also began to introduce initiatives to its regulatory program, including near-miss and failure reporting, third-party verification and certification, and RTM of facilities.3 On the basis of recommendations in external committee reports on the investigation of the Deepwater Horizon drilling rig explosion, BSEE’s RTM initiative began as a way of exploring how RTM technology could improve offshore drilling safety and 1 At the time of the accident, the Minerals Management Service (MMS) had authority for offshore oil and gas operations. In June 2010, MMS was renamed the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE). On October 1, 2011, the U.S. Department of the Interior reorganized BOEMRE and established two new, independent bureaus—BSEE and the Bureau of Ocean Energy Management (BOEM). 2 For more information concerning the implementation of BAST, see NAE and NRC 2013; the entire report is available at http://www.nap.edu/catalog/18545/best-available-and-safest-technologies-for-offshore-oil-and-gas-operations. 3 D. Morris, BSEE, presentation to the committee, December 2014.

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 2 operations. One report from the Office of Inspector General of the U.S. Department of the Interior contained recommendations identifying potential areas for improvements to the offshore safety program (OIG 2010). Of particular relevance is Recommendation 18: 18: Analyze the benefits of obtaining electronic access to real-time data transmitted from offshore platforms/drilling rigs, such as operators’ surveillance cameras and BOP [blowout preventer] monitoring systems, and/ or other automated control and monitoring systems to provide BOEMRE with additional oversight tools. Additionally, the National Academy of Engineering (NAE) and National Research Council (NRC) committee that evaluated the causes of the Macondo well blowout and Deepwater Horizon drilling rig explosion made many recommendations to reduce the risk of future blowouts in its 2012 report (NAE and NRC 2012). Two general recommendations addressed RTM: Recommendation 3.4: The instrumentation on the BOP [blowout preventer] system should be improved so that the functionality and condition of the BOP can be monitored continuously. Recommendation 3.5: Instrumentation and expert system decision aids should be used to provide timely warning of loss of well control to the drillers on the rig (and ideally to onshore drilling monitors as well). Although the RTM technologies offered new opportunities, BSEE had to consider what (if any) implications these technologies could have for BSEE’s regulatory and oversight role. To learn more about RTM technologies and best practices, BSEE conducted site visits to RTM centers during the summer of 2012 and then established an internal RTM team in the fall of 2012 to develop preliminary findings on how the oil and gas industry and BSEE could benefit from the use of RTM technologies. After working for more than a year, the BSEE RTM Team produced a final summary report, Summary of BSEE’s Real-Time Monitoring Study (BSEE Summary Report), detailing its findings and recommendations (BSEE 2014). More recently, BSEE commissioned a report to provide background on currently available technologies from the company 838, Inc. That report, An Assessment of the Various Types of Real-Time Monitoring Systems for Offshore Oil and Gas Operations (838 RTM Report) is dated February 10, 2014 (838, Inc. 2014).4 In July 2014, BSEE requested that the NRC Marine Board conduct a study on the use of RTM of offshore oil and gas operations.5 4 The complete 838 RTM Report and final presentation are available at http://www.bsee.gov/Technology-and-Research /Technology-Assessment-Programs/Projects/Project-707/. 5 More information about the study and the committee is available at http://www8.nationalacademies.org/cp/projectview .aspx?key=49661.

3RTM AND OFFSHORE OIL AND GAS OPERATIONS Monitoring of basic sensor data on drilling rigs has been an important part of drilling operations since the 1940s (Booth 2009, 2010). As technology advanced, the ability to capture more and better-quality data improved, and the information and data were sometimes used for trend analysis and anomaly detection on the rig. Improvements in telecommunications technology added value by allowing data transmission to other locations, data aggregation from multiple sources, and data analysis, all while permitting remotely located staff to engage with rig personnel. The opportunity to collect and manage data through a centralized onshore facility allowed many contractors to provide enhanced services (Booth 2009). Although many operators have used on-site (on the rig) RTD to monitor dynamic drilling processes (e.g., surface measurements and downhole tool readings) for years, some operators have, more recently, incorporated enhanced remote RTM as part of their standard management practices. For some large operators, the business case for remote RTM of drilling operations was made on the basis of improved efficiencies and enhanced risk management through better operational planning and execution. Although a business case may drive the purpose and justification of remote RTM centers, that case will differ for each company. Remote centers are almost always operated by highly experienced technical staff members, many with offshore experience, that monitor and communicate directly with rigs through both formal and informal protocols, providing an additional level of well monitoring for managing risks (Booth 2010). Well site personnel are assigned primary responsibility and decision making for all drilling operations. During drilling operations, remote monitoring centers can focus on abnormal trends or well events, providing an additional “set of eyes” for the rig, offering advice, support, and improved access to onshore technical experts; this allows rig personnel to concentrate on drilling operations. If rig personnel encounter operational issues that require assistance, RTM makes it possible to collaborate with specialists onshore, without the need to fly them out to the rig. Remote centers can also check the incoming information stream for valid and reliable data, which allows the development of a knowledge base and additional post-processing data analysis. RTM “improves HSE [health, safety, and the environment], reduces subsurface NPT [nonproductive time], and facilitates operational excellence;” additionally, RTM “improves the operator’s ability to effectively manage its leases.”6 Smaller operators may employ some elements of RTM, but some of these operators have concerns about the cost and practicality of continuously monitoring all drilling operations by an onshore staff. Staffing a 24-hours-a-day, 7-days-a-week (24/7) RTM center may be difficult given the limited number of qualified technical personnel. Wells and operations may have different risk or complexity profiles, 6 B. Gaston, Shell, presentation to the committee, December, 2014. INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 4 depending on such circumstances as geological factors, operational conditions, the extent of drilling, and the production history. RTM could be an appropriate tool when applied to more risky and complex wells and activities. The next section summarizes a recently completed research project by the company 838, Inc., that reviewed and assessed RTM technologies. 838, INC., ASSESSMENT OF RTM SYSTEMS REPORT In the fall of 2012, BSEE’s Technology Assessment and Research Program awarded a contract to the company 838, Inc., for additional research on the use of RTM for offshore oil and gas activities. This section summarizes many of the main topics from the more than 200-page report submitted by 838, Inc., and includes terms and concepts as used by the authors (838, Inc. 2014). The main tasks, along with many corresponding conclusions and recommendations for the research project, are listed in order below. Task 1 What is the current state of real-time monitoring (RTM) technology? Perform an independent assessment of the various RTM data systems available for offshore oil and gas operations, with a focus on: (a) drilling activities and (b) production technologies. Task 1 is addressed in Chapter 1 of the 838 RTM Report. The report found five basic uses for RTD technologies: 1. Subsurface and formation analysis and well planning and modeling tools. 2. Wellbore stability and drilling integrity (downhole) monitoring and analysis. 3. Instrumentation for drill floor and rig operations. 4. Bandwidth requirements for data collection, transmission points, wireless and wired, and standardized languages. 5. Onshore center—data aggregation standardized interfaces; screens; display of relevant data; user interface; predictive capabilities; and monitoring and alarming potential. Although 838, Inc., polled 164 oil and gas exploration and production companies with current operations in the Gulf of Mexico, only 76 companies responded. Of those that responded, more than half (41) reported using some type of RTD, and, of those that use RTD, 80% (33 companies) say that they send those data onshore. Of the

541 companies using RTD, 39% have some type of operations center; only 17% use a monitoring center that is staffed 24/7. The 838 RTM Report also notes that the use of RTD is increasing as sensor technology advances. Task 2 What is the cost–benefit of RTM? Perform a cost–benefit analysis of the systems identified that details: (a) potential costs to industry, (b) potential increases in safety performance, (c) government resources needed for implementation, and (d) necessary training for all parties involved. Task 2 is addressed in Chapter 7 of the 838 RTM Report. The authors noted that businesses need to be able to show both a return on investment and, ultimately, profitability. As part of their research on the cost–benefit analysis for RTM, the authors indicated that a cost–benefit analysis for a small company will differ greatly from one for a larger company. Other issues can influence the results of cost–benefit analyses, such as the timespan covered by an analysis or the area of focus (onshore or offshore). The authors also emphasized that some benefits are intangible and difficult to assess and that most corporate cost–benefit analyses are proprietary. For the report, the authors limited the scope of the cost–benefit analysis and included specific assumptions; they also stressed that the report’s cost–benefit analysis is only for illustration purposes. Even when conservative estimates are used in the cost–benefit analysis, the authors of the 838 RTM Report conclude that the use of RTM centers is justified. They note that barriers to the introduction and use of advanced principles for exploration and production are not always financial and that the government may have a role in promoting use. Likewise, they note that the benefits of RTM centers are not always financial; they can include improvements in safety and the environment. According to the authors, an RTM center can be a “powerful tool for increasing efficiency and elevating safety” (838, Inc. 2014, p. 218). Task 3 What training is needed for RTM? Discuss options for training programs or contracted services that would be needed to incorporate the identified systems into BSEE’s processes. Chapter 2 (for Task 3) of the 838 RTM Report included training options for incorporating systems necessary for RTD monitoring into an oversight role and the importance of standardization for the purposes of regulatory oversight. Before any effective training program can be developed, the authors believe that BSEE should INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 6 ensure that the oversight system is clearly defined. The authors discussed principles of safety oversight and system safety models, and introduced three training scenarios for the purpose of incorporating RTM into BSEE processes. Scenario 1 proposed a focused internship and syllabus of instruction with an oil and gas operator. Scenario 2 involved curriculum development; BSEE, in conjunction with industry, would develop a curriculum for training courses designed to help its personnel to a better understanding of the RTD technology available in the industry. Scenario 3 suggested the development of a simulation center within BSEE that would be modeled after an industry real-time operations center. Established and maintained within BSEE, this center would train BSEE personnel in best practices, using actual (de-identified) data to perform simulations or to replay actual events. The authors conclude that their example of safety oversight, as discussed in Chapter 2 of the report and as used in other regulated industries, is a proven model. This system safety model would manage the standardization of training while ensuring that stakeholders continue to generate industry best practices, evolving with technological advancements. Helping BSEE understand RTM through standardized training could also enhance industry safety. The authors recommend a combination of Training Scenario 1 and a hybrid of Training Scenario 2 and Training Scenario 3. Task 4 What are the critical parameters and operations to monitor? Identify all necessary information that has to be collected, calculated, or monitored during operations to improve the current level of safety. Task 4, which discusses critical operations and parameters, is addressed in Chapter 4. The authors focus on data and information that are more related to improved safety and less to nonproductive time and other operational efficiencies. Drilling operations produce multiple data flows, with the amount of data produced growing as technology advances. The authors note that collaboration centers with demonstrated reliability or performance improvements share five common success factors: 1. Environment—placing the operating condition of equipment in context; 2. Data—collecting and managing data by exception; 3. Analysis—employing both predictive analytics and deep diagnostics as complementary technologies; 4. Cooperation—communicating observations, recommendations, and lessons learned through collaborative tools; and 5. Management—utilizing a knowledge management system for organizing findings.

7The authors list and discuss collected, monitored, and calculated information for well operating conditions. Examples of data collected include pressure, hydraulic, torque, tension, and temperature. Monitored data can include fluid dynamics and pressures, mud flow and quantity and density, and mud temperature and properties. Calculated data examples can include hydrostatic pressure, pore pressure, and equivalent circulating density (ECD).7 The authors also discuss the importance of modeling and modeling tools for well planning and well development. Using RTD with available modeling technology offers great benefits to offshore operations, from drilling a well to post-drilling analysis. The authors list many types of process models that are available, including geomechanical and hydraulic ECD models (838, Inc. 2014, p. 125). These types of models, they note, can provide proactive responses to daily operational challenges, rather than reactive ones. Simulations with post-processed data are also important modeling tools, allowing the creation of operational and training simulations that provide improved situational awareness and procedural understanding. Suggesting that there is a need for a cultural shift within the industry to improve the safety of deepwater operations, the authors propose that operators demand from their contractors both improvements in the monitoring systems used and a higher quality of data collected, measured, and evaluated. The authors conclude that modeling of the well environment before the start of drilling has meant greater insight into the process and that the use of simulation programs that incorporate RTD during drilling operations contributes to increased efficiencies and can promote safe operations. Training simulators can enhance the experience of personnel, which can also improve safety. Task 5 How can RTM be used for condition monitoring? Identify technologies and data that might be helpful in measuring field performance of critical equipment with the goal of predicting potential failures. In Chapter 5, the authors survey current sensor technologies used by industry to measure and report performance and to predict failure of monitored equipment. The authors describe sensors and transducers and discuss how each works and is used to report conditions or to measure various instruments. Next, they discuss virtual sensors that merge collected data from existing sensors and with other historical performance data to predict conditions. Virtual sensors are also associated with data reconciliation, a process control technique used “to verify measured data by reference to a process 7 For a detailed list of data collected, monitored, or calculated, see 838 RTM Report (838, Inc. 2014, pp. 110–124). INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 8 model” (838, Inc. 2014, p. 136). The authors also describe fiber optic sensors as an important new technology for condition monitoring—they are small and reliable, can withstand high temperatures, can manage multiple sensing points on a single fiber, and are immune to most interference. There is also no spark hazard with fiber optic sensors. Other new technologies include fiber Bragg grating, an optical sensing technology used to measure such variables as temperature, pressure, weight, and flow, and microelectromechanical systems, a technology consisting of very small components (micro valves, pumps, and actuators) that can sense relative motion. Next, the report discusses the concept of the digital oil field and the importance of collecting, managing, and analyzing data. The foundation of the digital oil field is reliable and valid data, which, in turn, form the basis for all analysis and decision making. The authors briefly examine possible areas where technology could replace currently performed industry inspection techniques, such as the inspection of subsea pipelines and risers, liquid storage tanks, and floating vessels. The authors conclude that advancements in sensor technology have allowed industry to increase the amount and improve the quality of collected data from critical systems, leading to more efficient and reliable equipment. For example, the authors suggest that the analysis of newer, previously unavailable data from fiber optic sensors have permitted better decisions with a smaller margin of uncertainty. According to the authors’ research, the amount of currently recorded data is only a subset of the total available data; as more data are collected and recorded, industry will need newer and better methods of data storage, transmission, and analysis. The authors also suggest that newer sensors and the data they provide could replace many current inspection methods that are labor intensive. Task 6 What RTM requirements should be incorporated into BSEE’s regulations? Identify how RTM could be incorporated into the BSEE regulatory regime in either a prescriptive or a performance-based manner. The authors of the 838 RTM Report conclude that incorporating RTM requirements into the BSEE regulatory regime could have great benefits for the oil and gas industry, including promoting safe and efficient exploration, extraction, and production of hydrocarbons. The authors also maintain that the inclusion of RTM in BSEE’s regulatory regime should incorporate the principles of system safety if BSEE is to remain an effective regulator. The authors discuss components of system safety programs, including “as low as reasonably practicable” risk, root cause analysis, human factors analysis and classification, and predictive analysis, that would complement both each other and RTM regulations.

9The authors also state that voluntary reporting could enhance safe operations. To ensure that that the industry as a whole understands incidents and accidents, the authors suggest the implementation of industrywide data sharing among operators; BSEE would receive de-identified data, with any proprietary information protected. The authors also recommend that BSEE implement a voluntary safety reporting system that would expand the “reporting of unsafe working conditions” under the SEMS regulations and that BSEE identify and promote industry best practices and technology.8 Task 7 How can automation enhance RTM? Perform an assessment of automation technologies and their impacts on (a) human and environmental safety, (b) efficiency improvements, and (c) cost to industry. In Chapter 6 of the 838 RTM Report, the authors assess the current principles of automation and the automation now available in the oil and gas industry and detail automation’s effects on human and environmental safety, efficiency, and overall costs to the industry. They note that the automation and control of many offshore processes promises to improve safety, performance, quality, and reliability, but that the industry is divided into those companies that can afford this technology and those who might not be able to afford it. The authors note that the need for automation “is driven by the difficulty in tightly controlling critical well parameters during drilling operations for extremely deep wells” (838, Inc. 2014, p. 160). The authors also conclude that • Automation promises to limit human exposure to dangerous environments and to enhance safety through better control, • Automation can be enabled with the introduction and advancement of newer technology, and • The incentives for automation are the realization of economies of scale and predictable quality levels. The authors add that automation has definite human health and safety benefits, but that it also has several pitfalls and challenges surrounding its use, including mode confusion,9 complacency, the need for preventive maintenance, reliance on timely and high-quality data, and several other limitations, such as security threats and vulnerabilities. 8 In her workshop presentation, Susan Dwarnick of BSEE indicated that BSEE is moving ahead with this recommendation of a reporting program that captures information about incident near misses and trends and then returns that information back to industry. 9 Mode confusion is when an automated system behaves in a way that was different from what was expected, and the operator was not aware of or did not understand what the system was doing. INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 10 The authors discuss the status and progress of current automation technologies in such areas as fluid control, continuous motion rig, pipe handling, and autonomous undersea vehicles. Overall, the authors note that automation in the upstream oil and gas industry is in its initial stages and looks promising, but that some tasks in oil and gas operations may never be fully automated, always requiring some human involvement. Final Thoughts and Recommendations The 838 RTM Report authors conclude that the use of RTM centers is viable, and that the financial return from using RTM technology is supported by the study and the continued use of RTM by large operators. They observe that any government regulation of the use of RTM should be introduced gradually, starting with the drilling of high-risk wells. Further, they indicate that regulations should include the need for onshore monitoring of well parameters by a separate safety center. Small and medium-sized operators, they note, could use a common onshore monitoring center to share the financial burden; the government also could provide incentives to these operators to encourage use of such centers. The report authors also recommend that any RTM operation be audited periodically by the regulator to ensure that monitoring is occurring. They note that other countries are providing a roadmap through funding or supporting the introduction of automation on drilling rigs. The authors suggest that the U.S. regulator should fund and promote research in automation research to help foster an atmosphere of cooperation and could also form a team with regulators from foreign governments to share ideas and create a roadmap to fuller automation of drilling rigs. BSEE RTM SUMMARY REPORT This section summarizes the Summary of BSEE’s Real-Time Monitoring Study (BSEE Summary Report) (BSEE 2014). Established in October 2012, the internal BSEE RTM team focused on two primary questions:10 1. Use of RTM by industry: What minimum requirements should BSEE consider establishing in its regulations for the use of RTM technologies by the offshore oil and gas industry? 2. Use of RTM by BSEE: How should BSEE use RTM technologies to carry out its safety and environmental protection responsibilities more efficiently and effectively? 10 For more details on the questions the team considered, see the BSEE Summary Report, Table 1, “Questions Considered by RTM Team” (BSEE 2014, p. 5).

11 – How could BSEE use RTM to supplement and enhance its existing inspection program? – How could BSEE use RTM to expand and enhance its safety and enforcement missions? To accomplish its work, the team formed three subgroups that corresponded to three general categories of offshore activities: drilling operations, completion and workover operations, and production operations. Each subgroup was given the task of identifying critical operations and parameters during each offshore activity that should be monitored using RTM technologies. The subgroups’ complete feedback is listed in Annexes 1, 2, and 3 to the BSEE Summary Report.11 The feedback includes operations such as well control, negative tests, and kick detection for drilling, completions, and workovers, and emergency shutdown and temperature safety element status for production. Use of RTM by Industry According to the BSEE Summary Report, some major oil companies use RTM centers to monitor high-risk drilling and production operations,12 especially those in deep water. The report lists several components as critical for an effective RTM center. The first is the stream of data received from offshore sites that allows companies to provide a network of experts to support or assist their offshore operations. In direct communication with offshore sites, these experts can provide advice and troubleshoot issues from onshore without having to be flown out to the drilling rig or production platform. A second component is the communications link between the center and the offshore control room. Constant communication between an offshore site and the onshore center is vital if onshore personnel are to maintain awareness of offshore operations; center staff otherwise could misinterpret RTM data. Effective communication between offshore and onshore staff demands clear protocols and procedures on how to identify, verify, and escalate safety concerns, and also guidance on who should talk with whom. The third component is that the center be staffed with experienced and highly trained personnel who must then gain the trust of offshore personnel. Use of RTM by BSEE BSEE’s internal RTM team also considered BSEE’s role in monitoring RTM data from offshore facilities. Below is a summary of key issues that the BSEE team discussed: 11 The BSEE Summary Report contains feedback from the Drilling Subgroup (Annex 1, p. 14), the Completions and Workovers Subgroup (Annex 2, p. 17), and the Production Subgroup (Annex 3, p. 20) (BSEE 2014). 12 Although they are defined differently within the industry, high-risk operations are often a function of many factors, including, but not limited to, drilling depth, water depth, anticipated high temperature or pressure (or both), and complexity. INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 12 1. The BSEE team notes that RTM has the potential to be a powerful enabling technology that could transform offshore safety and environmental oversight for both industry and BSEE. – Any new step to improve BSEE’s inspection and enforcement program should consider (and possibly develop, test, and implement) reforms based on RTM technologies and risk-based inspections to supplement the current program. – BSEE should develop a risk-based strategy to determine which RTM opportunities provide the best return on investment and which activities still require on-site inspections. The focus would likely be on high-risk activities involving deepwater drilling and casing and cementing, with additional focus on problematic facilities and operators. – Because the objective is to improve its regulatory oversight of critical operations and equipment, the use of RTM could allow BSEE to shift technical resources to evaluate these operations and equipment more quickly. – Implementing a RTM program would be a change from BSEE’s current inspection program and would require a different skill set than BSEE’s traditional inspection activities do. – Any new program should be implemented in phases, with consideration for managing potential workload and hiring a sufficient number of staff. 2. An important task, according to the BSEE team, is to identify critical operations and parameters for drilling, completion, and workover and production activities. – Identifying the critical operations and parameters to be monitored has to occur before discussing any potential role for BSEE or requirements for industry. – Given its limited resources, any BSEE RTM oversight program would have to focus on critical operations—those that pose the greatest risk of a well control event; however, defining a critical operation may be difficult, because a well control event could occur at any time during downhole activities. – As detailed in Annexes 1, 2, and 3 to the BSEE Summary Report, the BSEE RTM team and its subgroups spent a considerable amount of time and effort identifying which critical operations and parameters to monitor during drilling, completion, and workover and production activities. 3. The team adds that it should consider what value-added role or roles BSEE personnel would take through overseeing critical drilling, completion, and workover operations. – Active oversight of downhole operations would be a new role for BSEE, one quite different from its current safety program for well operations, which primarily focuses on the review and approval of drilling plans and the inspection and testing of drilling and production safety equipment. – To avoid becoming a distraction during critical downhole operations, BSEE personnel providing oversight would need to have the proper qualifications,

13 experience, and technical training to contribute to the safety of the offshore operations; however, the team notes, recruiting and retaining personnel with such highly specialized skills and knowledge can be challenging for the federal government. – Even with the right expertise, the team believes that government personnel would be challenged in assuming an oversight role during complex operations without quickly assimilating all the safety issues and risk factors for a particular well operation. – Additionally, according to the team, any BSEE oversight role must consider potential legal implications. 4. Without direct communication between BSEE and the facility’s offshore control room, the team believes that any RTM data could be misinterpreted and have limited use. – Providing BSEE personnel with an additional direct communication link to the facility’s offshore control room could become a distraction to the offshore facility. – Because of concerns about proprietary information and potential legal liability for regulatory noncompliance, companies may be reluctant to share RTM data. 5. The BSEE team expresses concern that obtaining RTM data from multiple operators poses many unknown technological and legal challenges. – Any BSEE monitoring system incorporating various offshore RTM systems and data formats would have to resolve compatibility and technical issues, such as connectivity issues, bandwidth limitations, and cost factors. – Any legal issues regarding the protection of proprietary information and the legal implications of collecting and storing RTM data would have to be resolved. – Any new requirement that industry provide BSEE with access to RTM data could necessitate rulemaking by BSEE. 6. The BSEE team observes that Daily Drilling Reports from the International Association of Drilling Contractors (IADC) could provide useful information for BSEE oversight of drilling operations. – BSEE should determine if IADC Daily Drilling Reports could provide adequate oversight of drilling operations as a low-cost, low-technology alternative to BSEE monitoring of RTM data feeds. – BSEE regulations require operators to submit form BSEE-0133, Well Activity Report, to the BSEE district manager on a weekly basis. However, IADC publishes a Daily Drilling Report form that provides more detailed drilling information than form BSEE-0133. – Requiring the IADC Daily Drilling Report form to be submitted electronically to the BSEE district manager on a daily basis could be beneficial, although such a requirement might require rulemaking by BSEE. INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 14 Options for Incorporating RTM The BSEE RTM team discussed various scenarios for incorporating RTM oversight into the agency’s safety regime. Below are the three options that the team identified: 1. Oversight through RTM centers. BSEE personnel could travel to the RTM center of each offshore operator in order to access RTM data and monitor offshore activities. 2. RTM Internet portal. BSEE could establish an RTM Internet portal (a specially designed, password-protected website) that would allow BSEE personnel to access RTM data from offshore operators whenever needed by logging onto the portal. 3. BSEE RTM center. BSEE could establish and staff its own centralized RTM center, similar to an air traffic control center used by the Federal Aviation Administration or a vessel traffic service center used by the U.S. Coast Guard. The BSEE RTM team deemed that oversight through RTM centers (Option 1) and oversight through an RTM Internet portal (Option 2) are the more promising scenarios for incorporating RTM oversight into BSEE’s safety regime. Of those two, the BSEE RTM team believes that Option 1 would be easier, faster, and less costly to implement. Also, although Option 2 might provide useful data for monitoring offshore activities, the team noted that more research is needed before such a portal would be a viable option. Determining how to implement any RTM technologies for mitigating risk would require more research and outreach to industry and subject matter experts. The BSEE RTM team suggested conducting a public workshop to collect feedback about potential knowledge gaps and to obtain input guiding BSEE on a recommended path forward. The BSEE RTM team also recommended further evaluation of the idea of using IADC’s Daily Drilling Reports as a lower-cost alternative to implementing RTM technologies. The IADC Daily Drilling Report includes more information than form BSEE-1033 and the IADC form also appears to be widely used by industry. The team concluded that updating BSEE regulations to require the electronic submission of the IADC form to all BSEE regions on a daily basis makes sense. On the basis of its discussions and recommendations, the BSEE RTM team suggested additional research in the following four areas: 1. Consider whether to implement a BSEE oversight and emergency response capability for monitoring critical offshore oil and gas activities via the RTM centers already being used by offshore oil and gas operators (Option 1 above). 2. Conduct research on the feasibility of collecting RTM data streams from offshore drilling rigs and production platforms and developing an Internet portal so that BSEE personnel can access the RTM data (Option 2 above).

15 3. Conduct a more detailed evaluation of RTM technologies and best practices for drilling, completion, workover, and production operations by holding a public workshop and conducting follow-on research. The purpose of the public workshop and follow-on research would be to define more clearly – What the critical operations and parameters to monitor using RTM technology are; – What industry’s role should be in monitoring RTM data, and what the minimum requirements should be; and – What BSEE’s role should be in monitoring RTM data. 4. Evaluate the potential use of IADC’s Daily Drilling Report for drilling safety oversight by BSEE. NOTICE OF PROPOSED RULEMAKING During the period between the committee’s first meeting in December 2014 and the workshop in Houston, Texas, in April 2015, BSEE released two proposed rules. One rule, concerning requirements for exploratory drilling on the Arctic outer continental shelf (OCS), was issued on February 24, 2015 (Federal Register 2015a); 13 the other concerned BOP systems and well control and was issued on April 17, 2015 (Federal Register 2015b).14 Both proposed rules include RTM components as part of the new requirements. Arctic OCS Exploratory Drilling Operations Overall, the proposed rule would add to and revise existing regulations in Title 30 of the Code of Federal Regulations for oil and gas activities focused on Arctic OCS exploratory drilling and related operations that use mobile offshore drilling units. Although it is only a small section in the proposed rule, the RTM component would require companies to gather RTD. Specifically, the section would require the following data (Federal Register 2015a): §250.452 What are the real-time monitoring requirements for Arctic OCS exploratory drilling operations? (a) When conducting exploratory drilling operations on the Arctic OCS, you must have real-time data gathering and monitoring capability to record, store, and transmit data regarding all aspects of: 13 The new requirements for Arctic drilling are available at https://federalregister.gov/a/2015-03609. 14 The proposed blowout preventer rule is available at https://federalregister.gov/a/2015-08587. INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 16 (1) The BOP control system; (2) The well’s fluid handling systems on the rig; and (3) The well’s downhole conditions as monitored by a downhole sensing system, when such a system is installed. (b) During well operations, you must immediately transmit the data identified in paragraph (a) of this section to a designated onshore location where it must be stored and monitored by qualified personnel who have the capability for continuous contact with rig personnel and who have the authority, in consultation with rig personnel, to initiate any necessary action in response to abnormal data or events. Prior to well operations, you must notify BSEE where the data will be monitored during those operations, and you must make the data available to BSEE, including in real time, upon request. After well operations, you must store the data at a designated location for recordkeeping purposes as required in §§ 250.466 and 250.467. The rule would also require operators to transmit the data during operations to an onshore location, where it would be stored and monitored by technically capable personnel who have the authority, in consultation with rig personnel, to begin necessary action to a potential event or data abnormality. BOP Systems and Well Control Released on April 17, 2015 (on the Friday before the committee’s workshop), the proposed regulations would consolidate equipment and operational requirements— common to other subparts—and incorporate (and revise some) guidance provisions from several Notices to Lessees and Operators (NTLs) that are related to offshore oil and gas drilling, completions, workovers, and decommissioning. At present, the proposed rule focuses on BOP requirements, incorporating many industry standards, and revises or reforms requirements in the areas of well design, well control, casing, cementing, real-time well monitoring, and subsea containment. For the RTM component in §250.724, the proposed rule states (Federal Register 2015b): § 250.724 What are the real-time monitoring requirements? (a) When conducting well operations with a subsea BOP or surface BOP on a floating facility or when operating in an HPHT [high pressure, high temperature] environment you must, within 3 years of publication of the final rule, gather and monitor real-time well data using an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting all aspects of:

17 (1) The BOP control system; (2) The well’s fluid handling systems on the rig; and (3) The well’s downhole conditions with the bottom hole assembly tools (if any tools are installed). (b) You must immediately transmit these data as they are gathered to a designated onshore location during operations where they must be monitored by qualified personnel who must be in continuous contact with rig personnel during operations. After operations, you must preserve and store this data at a designated location for recordkeeping purposes as required in §§ 250.740 and 250.741. You must designate the location where the data will be stored and monitored during operations in your APD [Application for Permit to Drill] or APM [Application for Permit to Modify]. The location and the data must be made accessible to BSEE upon request. (c) If you lose any real-time monitoring capability during operations covered by this section, you must immediately notify the District Manager. The District Manager may require other measures until real-time monitoring capability is restored. Records and Reporting § 250.740 What records must I keep? You must keep a daily report consisting of complete, legible, and accurate records for each well. You must keep records onsite while well operations continue. After completion of operations, you must keep all operation and other well records for the time periods shown in § 250.741 at a location of your choice, except as required in § 250.746. The records must contain complete information on all of the following: (a) Well operations, all testing conducted, and any real-time monitoring data; (b) Descriptions of formations penetrated; (c) Content and character of oil, gas, water, and other mineral deposits in each formation; (d) Kind, weight, size, grade, and setting depth of casing; INTRODUCTION

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 18 (e) All well logs and surveys run in the wellbore; (f) Any significant malfunction or problem; and (g) All other information required by the District Manager. § 250.741 How long must I keep records? You must keep records for the time periods shown in the following table. You must keep records relating to: (a) Drilling; until 90 days after you complete operations. (b) Casing and liner pressure tests, diverter tests, BOP tests, and real-time monitoring data; until 2 years after the completion of operations. (c) Completion of a well or of any workover activity that materially alters the completion configuration or affects a hydrocarbon-bearing zone; until you permanently plug and abandon the well or until you assign the lease and forward the records to the assignee. ORGANIZATION OF WORKSHOP REPORT At its first meeting in December 2014, the committee confirmed with the sponsor that the workshop agenda (Appendix A) and final report would focus on the Gulf of Mexico region and would be designed in such a way as to address the five issues listed in the statement of task (Box 1), in addition to being informed by the two reports mentioned in the statement of task and described above in this chapter. A standard set of questions relevant to the statement of task is listed in Appendix B. Chapter 2 summarizes the prepared remarks of workshop presenters, comments made by workshop participants, and the ensuing discussion in chronological order from the April 20–21, 2015, workshop. The panel participants and general attendees are listed in Appendix C.

19 INTRODUCTION Box 1 STATEMENT OF TASK An ad hoc committee will conduct a study to advise the Bureau of Safety and Environmental Enforcement (BSEE), U.S. Department of the Interior, on the use of real-time monitoring systems (RTM) by industry and government to reduce the safety and environmental risks of offshore oil and gas operations. As part of its efforts, the committee will organize and hold a public workshop that is informed by a recently released BSEE external technical report on RTM for oil and gas operations and the preliminary findings from an internal BSEE RTM workgroup. The committee will develop the workshop agenda, select and invite speakers and discussants, and moderate the discussions. Subsequently, the committee will (1) issue an interim report summarizing the presentations and discussion at the workshop and any findings the committee draws from the event and from the BSEE technical report and (2) hold additional meetings to develop and provide a final report with findings and recommendations on the use of RTM by the offshore oil and gas industry and BSEE that address the five issues below. Specifically, the final report shall address: 1. The critical operations and specific parameters that should be monitored from drilling and producing facilities to manage and mitigate environmental and safety risks (e.g., to reduce the risk of well kicks, blowouts, and other sources of casualties). 2. The role that automation and the use of predictive software tools should play in RTM. 3. The role that condition-based monitoring (CBM) should play in RTM and describe how the operating equipment using CBM could be tailored to and/or used for RTM. 4. Whether RTM should be incorporated into BSEE’s regulatory scheme in either a prescriptive or performance-based manner. 5. How BSEE should leverage RTM to enhance its safety enforcement program.

REAL-TIME MONITORING OF OFFSHORE OIL AND GAS OPERATIONS 20 REFERENCES Abbreviations BSEE Bureau of Safety and Environmental Enforcement NAE National Academy of Engineering NRC National Research Council OIG Office of Inspector General SPE Society of Petroleum Engineers TRB Transportation Research Board 838, Inc. 2014. An Assessment of the Various Types of Real-Time Monitoring Systems for Offshore Oil and Gas Operations. BSEE, U.S. Department of the Interior. http://www .bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Projects /Project-707/. Booth, J. E. 2009. Drilling Operations Centers: A History of Functionality and Organizational Purpose—The First Generation. Presented at the SPE Digital Energy Conference and Exhibition, Houston, Texas, April 7–8. Booth, J. E. 2010. Real-Time Drilling Operations Centers: A History of Functionality and Organizational Purpose—The Second Generation. Presented at the SPE Intelligent Energy Conference and Exhibition, Utrecht, Netherlands, March 23–25. 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. Federal Register. 2015a. Oil and Gas and Sulphur Operations on the Outer Continental Shelf—Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf; Proposed Rule. Vol. 80, No. 36, February 24, pp. 9915–9971. https://federalregister .gov/a/2015-03609. Federal Register. 2015b. Oil and Gas and Sulphur Operations in the Outer Continental Shelf— Blowout Preventer Systems and Well Control; Proposed Rule. Vol. 80, No. 74, April 17, pp. 21503–21585. https://federalregister.gov/a/2015-08587. NAE and NRC. 2012. Macondo Well Deepwater Horizon Blowout: Lessons for Improving Offshore Drilling Safety. National Academies Press, Washington, D.C. https://www.nae .edu/Publications/Reports/53926.aspx. NAE and NRC. 2013. Best Available and Safest Technologies for Offshore Oil and Gas Operations: Options for Implementation. National Academies Press, Washington, D.C. http://www.nap.edu/download.php?record_id=18545. OIG. 2010. A New Horizon: Looking to the Future of the Bureau of Ocean Energy Management, Regulation and Enforcement. CR-EV-MMS-0015-2010. U.S. Department of the Interior, Washington, D.C. https://www.doioig.gov/sites/doioig.gov/files/A-New -Horizon-Public.pdf. TRB. 2012. Special Report 309: Evaluating the Effectiveness of Offshore Safety and Environmental Management Systems. Transportation Research Board of the National Academies, Washington, D.C. http://www.trb.org/Publications/Blurbs/167249.aspx.