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49 In Chapter 1, the nature of real-time monitoring (RTM) and remote RTM (RRTM) activity in the oil and gas industry was introduced, along with the priorities of the Bureau of Safety and Environmental Enforcement (BSEE) and the charge of this committee. Chapter 2 provided a brief overview of offshore drilling and production operations and described the use of RRTM in the oil and gas industry. The last section of Chapter 2 summarized key points from two previous reports on the application of RRTM (BSEE 2014; 838, Inc. 2014) and from the summary of an industry workshop held by the committee (TRB 2015). Chapter 3 begins with a brief examination of best available and safest technology (BAST) as it relates to RRTM. Next, the notional benefits of RRTM in the oil and gas industry are illustrated with four use cases. The cases do not represent the full potentiality of RRTM, but they illustrate possible applications. After this presentation, several considerations for applying RRTM to the delivery of these use cases are examined by discussing issues such as data management, cybersecurity, and human factors. Finally, the potential role of RRTM in risk-based regulations and the possibility of using real-time data for condition-based maintenance (CBM) are considered. RRTM AS BAST The Outer Continental Shelf Lands Act mandates the use of BAST in offshore drilling and operations âwherever practicableâ and âeconomi- cally feasible.â1 After the Macondo well blowout and Deepwater Horizon 3 Benefits of and Considerations for Remote Real-Time Monitoring 1 See Public Law 95-372, Section 21(b): â[T]he Secretary . . . shall require, on all new drilling and production operations and, wherever practicable, on existing operations, the use of the best
50 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations explosion, BSEE requested a study from the National Academy of Engi- neering (NAE) and the National Research Council (NRC) that would provide options for improving the implementation of BAST. The final report (NAE and NRC 2013) provides insights into the meaning of BAST and identifies and evaluates specific technologies. More recently, BSEE developed a three-stage process for identifying candidate technologies for BAST determinations on the basis of an evaluation of the best-performing technology that is currently available. The director of BSEE initiates the BAST determination process and makes the final BAST decision.2 The current committee views RRTM in the context of BAST and believes that, as a technology that could reduce risks in particularly complex wells or projects, it could become more generally available to the offshore oil and gas industry and be a part of its tool kit for appropriate situations. By describing RRTM as BAST, the committee is not suggesting that its use be made mandatory on all wells. If RRTM is determined to be BAST by the director of BSEE, it could be considered an appropriate technology for monitoring operations and managing risk, and its use could be evalu- ated against the framework developed by the previous NAE-NRC BAST committee, as outlined in the following paragraphs. RRTM has developed over the past decade as technology improvements have allowed the transfer of increasing volumes of data to remote locations for monitoring and evaluation in real or near real time. For the offshore industry, the remote location is typically the onshore offices of the opera- tor or selected contractors. The increasing capability for managing data has in effect pushed the technology into wider implementation as companies identified opportunities to utilize RRTM to manage complex operations more efficiently, engage onshore expertise, and improve the management of safety. At the same time, the increasing complexity of many offshore drill- ing and producing operations (e.g., greater water depths, high-pressure or high-temperature subsurface environments, and increasing physical available and safest technologies which the Secretary determines to be economically feasible, wherever failure of equipment would have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies.â 2 More detail about the BSEE BAST determination process can be found at http://www.bsee.gov/bast/.
Benefits of and Considerations for Remote Real-Time Monitoring 51 scale for equipment and operations) has created a technology pull, whereby new solutions are needed in technology deployment for cost-effectiveness and better safety management. The decision whether to utilize RRTM on any particular well must recognize the complexity of the operating environment and of BAST implementation. RRTM must be evaluated as a candidate technology for managing risk, with consideration given to the overall complexity of the engineered and human systems. Consistent with the BAST committeeâs framework, any implemen- tation of RRTM as BAST could be considered relative to its potential contributions to overall safety, consistent with the principle of ALARP (as low as reasonably practicable),3 where practicability is interpreted as encompassing both technological availability and economic feasibility. NOTIONAL BENEFITS OF RRTM Traditionally, industry has used RRTM to improve efficiency and effective- ness through drilling optimization and better well planning and execu- tion. In the following section, the committee presents four high-level illustrative use cases that provide examples of the notional benefits of applying RRTM: â¢ RRTM and wellbore integrity and early kick detection, â¢ RRTM enabling augmented competencies from onshore, â¢ BSEE regulatory oversight and inspections with the help of RRTM, and â¢ RRTM and CBM of critical equipment. RRTM and Wellbore Integrity and Early Kick Detection Monitoring for well integrity and control, particularly early kick detec- tion, is one of the most important challenges for offshore operations. Well integrity has multiple facets and often refers to the application of technical, operational, and organizational solutions during the life cycle of a well to reduce the risk of uncontrolled release of formation fluids. 3 http://www.iadclexicon.org/as-low-as-reasonably-practicable/.
52 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations A âkickâ refers to the entry of formation fluid into the wellbore (or drilled hole) during drilling operations. It can occur when the pressure exerted by the column of drilling fluid is not great enough to balance the pres- sure exerted by the fluids in the formation being drilled. Kick prevention is a fundamental aspect of well integrity and control. If kicks are not addressed appropriately, they can lead to loss of well control and to a blowout. Offshore personnel must perform RTM of drilling operations and equipment status. For example, the driller is primarily responsible for monitoring the parameters associated with well control. At the offshore facility, monitoring by the driller is backed up by the mud logger or the drilling superintendent (also known as the company man), or both. Before the ready availability of broadband data at onshore office facili- ties, the role of remote personnel was limited to after-action review and long-term trend monitoring. The availability of significant real-time information to onshore locations has led to the possibility of additional and more complex monitoring of critical activities. However, the nature of these data is diverse and distributed. Many of the crucial data are collected by the mobile offshore drilling unit (MODU) operator, but some critical data are also collected by third-party service providers. Historically, the lease operator may not own or be provided with all the data that are generated on a MODU. Command and control issues become more complex when an RTM component is added. According to universal practice, the on-site com- mander (i.e., the driller) is in charge of real-time decision making. The addition of remote monitoring centers raises the possibility of confusion concerning who is in charge and of distractions during emergency or time-critical operations. Theoretically, monitoring centers can support detection of incipient problems, since onshore, remote personnel are less vulnerable to the distractions and concerns experienced by onboard MODU personnel. However, not all the data are available to onshore remote personnel, especially with regard to situational awareness dataâ data helpful in understanding what is occurring on the offshore facility. Data without context could lead to erroneous decision making. RRTM could be effective if comprehensive data are provided from the MODU and if roles and responsibilities for decision making are well
Benefits of and Considerations for Remote Real-Time Monitoring 53 defined. Such changes in data collection would require modifications of commercial arrangements and contracts, as well as hardware and software connectivity.4 The technical problems of transmitting and displaying the data may be the least difficult aspect of RRTM. As mentioned above, the driller monitors parameters downhole at the MODU to detect kicks. The parameters include mud pit levels, pump volumes, various pressures on the rig floor, and downhole measure- ments. Situational awareness of valve positions, piping runs, and other rig activitiesâsuch as crane operationsâis important, as are the values of mud weight and returns. The driller has other concurrent responsi- bilities and multitasks between monitoring well control parameters and operating the necessary equipment. RRTM for early kick detection would require all the information that is provided offshore, but it could focus on well control, if desired, and exclude anything else. RRTM for kick detection must not replace offshore personnel as the primary control for this hazard. Caution must be taken to ensure that offshore personnel do not become so reliant on onshore RRTM that they lower their surveillance of critical parameters. A short checklist of the necessary conditions for effective RRTM for early kick detection includes the following: â¢ The right data must be provided to the remote location, including situational awareness information. â¢ The remote (onshore) personnel must be trained and competent, and preferably experienced, in well control monitoring. â¢ Collaboration without distraction and a well-defined protocol for interaction with offshore personnel are required through a direct line of communication. â¢ The remote personnel must not be burdened with monitoring an excessive number of operations or with office activities. â¢ The remote personnel must have ready access to additional onshore expertise in the areas of well design, engineering, and geophysical information and interpretation. 4 A. Jaffrey, Cameron, presentation to the committee, August 2015.
54 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations â¢ The onshore expertise must be available for consultation with the offshore personnel. â¢ A clear line of communication and communication protocols must exist between onshore and offshore personnel. Even with state-of-the-art technology, the most reliable kick detection is via experienced personnel on the rig. The committee acknowledges that the industry has invested in and continues to work on smart systems, which could aid in early kick detection, but is unaware of any proven commercially available automated kick detection software or other system that provides warning of a pressure problem during drilling operations. Dual gradient drilling5 is one example of a method for enhancing kick detection through better fluid monitoring capabilities, and RRTM serves as a key enabler of this technology. RRTM Enabling Augmented Competencies from Onshore RRTM started with the desire of many operators to apply real-time information from downhole sensors to their operational decision mak- ing, such as formation evaluation, casing depth setting, and completion strategy. Once the data were collected and transmitted back to shore, the operator was better able to engage with a global group of situation- specific, technical experts. In turn, some operators chose to develop formal RRTM facilities and created protocols for interacting with personnel on the MODU. With the appropriate communication protocols in place, RRTM can enable additional competencies located onshore to support a decision offshore. RRTM centers monitor fleet operationsâwhere the term âfleetâ describes like equipment or like parametersâacross multiple drilling or production facilities and provide checks relating to key activities. While complexities and challenges with regard to data quality, data transmission, and data management exist, RRTM operations facilitate the comparison of historical and real-time, fleet-based operational data, 5 Dual gradient drilling holds promise for enhancing early kick detection. See http://oilprice .com/Energy/Energy-General/Chevron-has-Unveiled-New-Ship-to-Perform-Dual-Gradient -Drilling.html.
Benefits of and Considerations for Remote Real-Time Monitoring 55 including topics such as nonproductive time and blowout preventer (BOP) availability. Empirical data collected at the fleet level are essential for validating and iterating predictive maintenance models such as CBM and, in turn, increase the value that RRTM can provide over the long term. RRTM facilities generally replicate instrumentation and screens used in monitoring critical offshore systems. Remote monitoring centers can provide core onshore resources for well operations planning and for deci- sion support for offshore operations. If experienced engineers, geologists, and other technical specialists are located at the remote center, the ability to solve problems during drilling and completion activities also improves. Real-time events occurring offshore can be analyzed and interpretedâ on a permanent or on-call basisâby the technical expertise in remote centers. The centers, located worldwide, enable quick collaboration with onshore specialists, engineers, and management without the need of flying them offshore, which is time-consuming, delays decision making, and increases overall safety risk. By adopting RRTM into their opera- tions, operators, service providers, and original equipment manufacturers (OEMs) have access to the entire office staff in real time, without the safety risk exposure and travel time associated with trips offshore. Many opera- tors also reported improved efficiencies when they used RRTM to engage onshore resources in a timely manner. BSEE Regulatory Oversight and Inspections with the Help of RRTM One of BSEEâs goals for using RRTM is to reduce the costs and risks associated with the offshore presence of regulators. The BSEE inspection and enforcement program could use the information from RRTM and from other filings by offshore operators to focus limited resources on critical operations and improve preparation of inspectors before on-site visits. For example, inspectors could research operation plans, permits, and prior inspections and perform paperwork duties before the offshore visit. Archived RRTM data could also support the risk-based regulatory program that BSEE has adopted, which is discussed in more detail at the end of this chapter. The information would come not only from RRTM operations but also from required documents, such as the Application for Permit to Drill, the Deepwater Operations Plan, and the Safety and
56 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations Environmental Management System (SEMS) plan; daily drilling reports; and historical information from past operations and an industry knowl- edge base. The internal BSEE RRTM report illustrates several ways in which information collected from an operatorâs RRTM process can help inspec- tors get better prepared (BSEE 2014). RRTM, in itself, may not cut down on the number of offshore visits, but it could make inspectors more effective and efficient on each visit. As noted at the committeeâs April 2015 workshop, offshore operators prefer that inspections continue to be on site, but they are willing to host inspectors in their onshore drilling and production support centers. The lack of standardization in RRTM solu- tions used by the industry will make the training of BSEE inspectors in the various solutions challenging. However, reduction by BSEE of the num- ber of on-site inspections may be difficult as long as regulations require periodic inspections of each offshore facility. A later section in this chapter describes in greater detail how BSEE could integrate RRTM into a risk- based regulatory approach. The BSEE internal report discussed various scenarios for incorpo- rating RRTM into its safety and environmental enforcement program (see BSEE 2014). However, to accomplish this, operators with established onshore RRTM centers who presented to the committee indicated that the following elements need to be considered before a commitment is made to an RRTM center: â¢ The investment needed to set up the infrastructure for RRTM and to operate, â¢ Development of standards and a formalized operational workflow, â¢ Specific communication protocols required for the interaction between onshore analysts and offshore operators, â¢ Specialized skill sets needed by RRTM staff, and â¢ Understanding and appropriate use of monitoring tool technologies. Any organization considering establishment of an RRTM capability will need to investigate each of these elements carefully before proceed- ing. BSEE noted in its report that implementing any RRTM program (from visiting an operatorâs center to establishing its own center) would be a change from its current inspection program and would require skill
Benefits of and Considerations for Remote Real-Time Monitoring 57 sets different from those used in BSEEâs traditional inspection activities (BSEE 2014). BSEE personnel involved with RRTM operations would need to have the proper qualifications, experience, and technical train- ing to contribute to the safety of complex offshore drilling and pro- duction operations. The committee acknowledges that recruiting and retaining personnel with these skills could be challenging for the federal government. Under RRTM, the operator will still be accountable for safe operations on the offshore facility. RRTM could assist BSEE in improving regula- tory oversight of critical operations. However, close involvement with an operatorâs RRTM operations will raise issues such as protection of pro- prietary information, avoidance of confusing communications, potential legal liability of sharing information, the repercussions of shutting down a well, and the complex context or situational reality on the MODU or offshore facility. As reported to the committee through its workshop, the deployment and use of RRTM by industry exhibit varying levels of maturity among companies. Maintaining personnel with the necessary competencies for staffing a remote center is difficult. Technologies in use by the industry differ and can change over a short time. The objectives of requiring the use of RRTM need to be specified before industrywide standards can be developed. Until then, individual companies will follow their own internal guidelines and best practices. The subsequent section of this chapter on risk assessment and risk-based regulations expands on this notional example with a deeper discussion of opportunities and challenges of applying RRTM to assist BSEE in its regulatory oversight. RRTM and CBM of Critical Equipment Onshore parameter monitoring and CBM of critical safety and operational equipment on the MODU are emerging areas within RRTM. Although the oil and gas industry can cite remote monitoring examples that have been deployed for more than two decades, the application and breadth of such RRTM examples are limited. In general, the oil and gas industry and other industrial segments such as transportation are experiencing a merging of operational technologies, such as rotating equipment, pressure control equipment, and helm-based systems, with traditional information technology infrastructure. Performance-based or uptime models that rely
58 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations on sophisticated data management and data analytics are also arising, with a long-term objective of CBM. One trend has been the increased sophistication of on-equipment control systems. They can capture many parameters that collectively describe the equipmentâs use, such as cycle counts, housekeeping data, and state of operation. Such systems often can call home and in many cases provide the remote operator onshore with read-only access to all the system configuration screens that a MODU technician could access. These control systems may also be able to upgrade system software or firmware remotely, and some systemsâif enabledâcan control equip- ment fully from onshore. Such remote capabilities enhance the provision of support from available onshore expertise when problems occur. Early adoption of remote monitoring has occurred in three areas: the more recent generations of BOPs, subsea production, and MODU rotating equipment (such as power generation and compression).6 The benefits of this approach are linked mainly to operational efficiency associated with the equipment and elimination of unplanned outages, but a longer-term goal could include CBM services (Jaffrey 2015). RRTM facilities generally replicate instrumentation and monitoring screens used to operate mission-critical systems deployed offshore and include systems such as BOPs, mud circulation systems, downhole tools, and subsea production controls. By using familiar interfaces and aggre- gated historical trend data, expertise located onshore canâon a perma- nent or on-call basisâanalyze and interpret real-time events occurring offshore. In the near term, RRTM operations can provide enhanced situational awareness and augmented competencies to decision makers located offshore. In the longer term, onshore RRTM facilities will likely become a primary conduit for fleet data and serve as the basis for predic- tive modeling and CBM. A greater array of deployed sensors and the ability to aggregate fleet maintenance data are two preconditions for CBM programs. Maintenance of sensors and their proper calibration and reading are essential for CBM. CBM provides service life-cycle enhancements, with the aim of funda- mentally changing service from an interval basis to a predictive basis. The 6 For an early subsea example, see http://offshore.no/sak/52607_more_subsea_monitoring_for _snohvit.
Benefits of and Considerations for Remote Real-Time Monitoring 59 benefits to the operator working offshore are significant and include increased equipment uptime, a long-term objective of no unplanned outages, and a better planning horizon for necessary interventions. Recently, Diamond Offshore and GE Oil and Gas entered into a 10-year arrangement for selected BOPs that mimics similar performance-based or uptime models in use within aviation and other industry ver tical markets.7 Fundamentally, these business models shift ownership and performance accountability of the asset to the OEM. Since uptime is the primary payment criterion, these long-term contracts provide an incentive for the OEM to aggregate and analyze real-time and historical data for improved equipment availability, better safety, and, ultimately, prognostics (predictive modeling and CBM). This approach simplifies technology pull and allows the OEM to pursue technology upgrades (e.g., sensors, control systems) across an OEM-owned BOP fleet with greater efficiency and expediency.8 The advent of these models in the BOP segment as well as in other on-rig equipment (turbines, compressors, pumps) will bring about new dynamics, including business models that benefit from an increased reliance on predictive capabilities that aspire to CBM.9 Over time, greater adoption of RRTM will drive the necessary data standards, data infrastructure, and data systems to realize the potential of CBM. A later section of this chapter, Potential of CBM and RRTM, expands on how RRTM could advance CBM and discusses some of the challenges that would need to be addressed to do so. Summary The preceding four high-level use cases do not represent the full poten- tiality of RRTM, but they illustrate applications that differ in scope and context. For more than two decades, industry has used RRTM to improve 7 In a vertical market, businesses cater to the needs of a particular industry, such as aviation. See also http://www.maintenancetechnology.com/2012/06/the-rolls-royce-of-effective-performance -based-collaboration/. 8 The assumption is that the OEM can deploy updates into the fleet more effectively given direct ownership of the assets, which simplifies the technology commercialization cycle to some degree. 9 For example, see Diamond Offshore Drillingâs pressure control by the hour model, http://investor .diamondoffshore.com/phoenix.zhtml?c=78110&p=irol-newsArticle&ID=2136291, and GEâs engageDrilling Services, https://www.geoilandgas.com/drilling/offshore-drilling/engagedrill ingtm-services-contractual-service-agreements.
60 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations efficiency and effectiveness through drilling and optimization and better well planning and execution. These efforts helped bring about formalized remote operations centers that can use competencies available onshore to increase overall efficiency of remote drilling and production operations. In addition to driving better support for decision making, real-time com- petency augmentation from onshore decreases the need for travel offshore, which in turn enhances safety. The state of the art of RRTM could notionally support enhanced regu- latory inspection from offshore, although industry expressed concerns with regard to the scope and breadth of such initiatives. BSEE and indus- try collaboration to determine how RRTM could support or enhance traditional on-rig inspection regimes was generally encouraged at the committeeâs workshop. Options concerning how BSEE could integrate RRTM into a risk-based regulatory approach are discussed later in this chapter. The fourth use case, on the potential of CBM, introduces the need for persistent, high-fidelity sensor data from equipment to train or validate predictive models. RRTM can provide operators, service companies, and OEMs with vital empirical data for developing CBM. The potential of CBM is examined in greater detail in the last section of this chapter. CONSIDERATIONS AND CHALLENGES FOR RRTM The use of real-time data is increasing, especially as sensor technology advances and as the ability to transmit that data improves. At its April 2015 workshop, the committee was told about the importance of reliable and consistent sensor data for RTM, and the basis for any RRTM endeavor is reliable and valid data. Remote centers could help achieve this goal by checking the incoming information stream and allowing the development of a knowledge base and additional postprocessing data analysis, which leads to analysis and decision making. As noted in Chapter 2, the authors of the 838, Inc., report discuss the importance of collecting, managing, and analyzing reliable and valid data in the context of the digital oil field. The authors surveyed sensor technologies used by industry to measure and report performance and to predict failure of monitored equipment. They note that advancements in sensor technology have allowed industry to increase the amount and improve the quality of data collected from critical systems, which has
Benefits of and Considerations for Remote Real-Time Monitoring 61 led to more efficient and reliable equipment. According to the authorsâ research, the data recorded are only a subset of the total available data. As more data are collected and recorded, industry will need better methods of data storage, transmission, and analysis (838, Inc. 2014). Remarkably, fewer sensors are installed on subsea equipment, for reasons such as cost, the absence of regulations, and the lack of standards (Jaffrey 2015). Several data management issues must be addressed when an RRTM center is set up. The success of such a center in adding value to the drill- ing or production operations being monitored obviously depends on the technical expertise available onshore as well as the protocols established for intervention. The centerâs success could also depend on how effectively numerous data management issues are addressed. The remote center staff and any onshore expertise that is accessed through the center will be limited by what data are available to them, how those data are managed in real time, and how data are stored and managed for the longer-term uses of trend analysis, lookbacks, and investigations. Data Management and Technological Concerns for RRTM The committee has identified some of the data management issues with particular relevance to RRTM. The following review is not exhaustive, but it highlights the kinds of issues and questions about data and data management that will need to be addressed in establishing and running an RRTM center. Data Capture and Data Streaming Large volumes of data are available offshore, but where companies currently operate real-time centers, only a small percentage is actually transmitted to shore. For example, one operator at the committeeâs April 2015 workshop estimated that one of its drilling rigs provided more than 6,000 streams of data, yet the operator transmitted only about 60 of those data streams to the remote onshore center. The choice of what data are transmitted is critical. Bandwidth limitations for transmission to shore will typically influence those choices. Regardless of what data are transmitted, the lack of situational awareness onshore is an important issue in todayâs operations.
62 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations Data Management Real-time data on a MODU or a production platform are first aggregated offshore in a specialized data store for sensor and process control system data, or an electronic data recorder. This establishes a beginning point for data ownership by the operator. In RRTM, an onshore data warehouse can be established as a repository for integrated data used for reporting and data analysis. Under the traditional approach to managing offshore data, maintenance of the appropriate balance between data access and data confidentiality among all the parties is difficult. When data protec- tion is emphasized, data distribution is limited, and often critical data are not shared among all parties that need the information. This can defeat the purpose of the RRTM center, since onshore staff may not have full access to the data necessary to support offshore operations and decision makers. If data access is emphasized, data ownership and confidentiality can be violated. Without a complete systems view of the data life cycle, these factors are difficult to manage. Furthermore, if establishment of remote centers means that real-time data must be transmitted to gov- ernment entities, industry might require additional guarantees on data protection and data securityâwhat data are required, how the data will be used, and who will have access (TRB 2015). Data Quality and Integrity As offshore installations become more heavily instrumented and as advances in communications technology allow more data to be streamed to shore, operating practices need to evolve to support the new data systems. Sensor maintenance and data integrity will be critical. Lim- ited data transmission could result in lower levels of data redundancy in the remote center, and therefore the data that are available must be trustworthy. Data Governance and Ownership Implementing data governance means translating business needs into business and data management processes. Roles and responsibilities for collecting and managing all types of data must be defined, and cross-functional data standards must be applied. Data protocols, such
Benefits of and Considerations for Remote Real-Time Monitoring 63 as WITSML and PRODML,10 ease the difficulty of exchanging data between systems and companies. Good data governance manages the data relationship between offshore facility and onshore center. Current contracts between operators, drilling contractors, and service compa- nies often lack specific requirements for collecting digital data and fail to define the responsibilities of each party in managing, distributing, and processing data from the field. Furthermore, few (if any) standards exist for collecting the data needed for remote monitoring (Jaffrey 2015). Issues such as proprietary data streams managed by the operator or vari- ous contractors add to the technical data collection and interpretation challenge. Current data practices make holistic, data-driven actions and decisions difficult or impossible in an onshore support center. Data Integration Typically, in offshore operations data integration means merging sub- sets of operating data from the exploration, production, and accounting functions. For RRTM, this level of integration falls short. The integration of data must span the entire value chain and link diverse data sources and types. To realize the full potential of RRTMâincluding the implementa- tion of CBMâcapturing and linking data across the life of a compo- nent or facility will be necessary, regardless of where the component or facility is located or who is the owner. An integration framework allows the seamless transfer of information through proper data management practices, reports, and operational dashboards. The purpose of an inte- gration framework is to enable the transfer of information between vari- ous functions and applications according to a defined workflow and to enable the presentation of information in a way that facilitates decision makingâin a word, interoperability (Crompton and Gilman 2011). Analytics Many of the data collected from RTM during the drilling process will become more useful as big data applications for the oil and gas industry 10 WITSML (Wellsite Information Transfer Standard Markup Language) is a standard for sending wellsite information; PRODML (Production Markup Language) is a standard for drilling and production data.
64 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations are developed in the near future. These data will allow companies to analyze just-in-time options for the oil field, to improve control of their drilling programs and rig schedules, and to have better insight into sup- plier contracting possibilities. The foundation for realizing these benefits is proper design of an RTM system. Emerging Technologies The impacts of several emerging technologies have yet to be felt fully within the offshore industry. These technologies could affect the design and operation of RRTM and monitoring centers within the foreseeable future. Among them are the following: â¢ Big data platform would bring issues concerning the volume, speed, and diversity of real-time data into clearer focus. â¢ Under cloud computing, infrastructure-as-a-service would challenge the industryâs traditionally conservative position on data privacy and security. â¢ Under advanced analytics, functional and operational models (e.g., res- ervoir modeling or geosteering) use real-time data to develop insights and manage work processes in real time. â¢ Mobility makes more real-time data available on mobile platforms in more locations and locations far from a remote monitoring center, and companies take advantage of this data availability to improve the management of business processes, further challenging long-held models for data management and security. â¢ The industrial Internet of Things will enable the growth of oil field sensor and control systems and provide more data to staff in remote locations that will produce more timely interventions and improve operational insights. As stated earlier, this section is not intended as a complete review of data and data management challenges in RRTM. Instead, it high- lights the more significant challenges that the committee identified and briefly frames these issues in the context of the development and application of RRTM. Most of these challenges were raised by mem- bers of industry during the April 2015 workshop and during visits by the committee to operating and service companies throughout 2015.
Benefits of and Considerations for Remote Real-Time Monitoring 65 As more companies use RRTM in managing offshore operations, the scope of these issues will grow from single-company problems to industry- wide challenges. Cybersecurity and RRTM Connectivity and communication between onshore and offshore facili- ties are important in efficient and safe offshore operations (TRB 2015). Connecting onshore and offshore facilities has been motivated by opera- torsâ desire to âincrease productivity, reduce costs, and share information in real time across multiple industrial and enterprise systemsâ (Byres 2012). With increased reliance on connected devices and software-aided decision making, the risks posed by cyber-based threats have grown since the beginning of the preceding decade. In addition, process equip- ment depends on computer technology to a greater extent, which creates computer-based vulnerabilities independent of connectivity. According to the Repository for Industrial Security Incidents, half of all security and safety incidents related to industrial control systems reported from 1982 to 2010 were due to malware, external attacks, or internal attacks (Byres 2012), which suggests the need to mitigate a broad set of vulnerabilities. Increased use of RRTM of offshore operations and equipment will place new demands on the instrumentation of drilling and production equipment and further drive demand for connectivity and bandwidth for offshore operations. The increased use of mobile devices to display information has added risk (TRB 2015, 33). Operational technology systems, such as legacy programmable logic control (PLC) systems and supervisory control and data acquisition (SCADA) systems for mission critical rig-based equipment, were not designed for connectivity to Internet-facing systems and were not necessarily designed to be resilient to computer-based incidents that corrupt or alter software in an unauthor- ized way, whether intentionally or unintentionally (Hsieh 2015). Modern MODUs feature many systems that are Internet-capable, but they lack âawareness of true risks and governance to ensure proper cyber risk managementâ (Endress 2015). Traditionally, control system networks were air gapped or separate from Internet-facing networks, which minimized accidental or malicious
66 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations attacks.11 To a greater extent, control systems have been connected to Internet-facing networks, which allow more effective asset management and greater process efficiency. This connectedness can increase exposure of control-system-based targets, such as SCADA- and PLC-based systems, and increase potential pathways (or points of entry) (Byres 2012). Safety and security threats are expected to grow, which suggests a need to focus on issues related to physical harm or the environment. The Stuxnet12 computer worm is an example of a computer-based attack, and a news report indicated that a German steel plant was damaged by a computer attack in 2014.13 Documented cyberattacks on oil and gas facilities include a 2008 oil pipeline explosion in Turkey and a 2012 virus that infected up to 30,000 computers on Saudi Aramcoâs network (Hsieh 2015). Accord- ing to the Ponemon Institute, companies in energy and utilities recorded increased annual costs due to cybercrime,14 and an ABI Research study predicted that global cyberattacks against oil and gas infrastructure could cost companies up to $1.87 billion by 2018.15 PriceWaterhouseCoopers reported that cyberattacks in the oil and gas industry during 2014 increased from the previous year and will likely continue to do so.16 Vulnerabilities specific to control systems include poor risk ana l- ysis; poor design, testing, certification, and hardening of control system equipment; poor awareness and management of the vulnerabilities; and human error (Johnsen 2012; DNV GL 2015). The vulnerabilities can be mitigated and controlled through systematic work focusing on cybersecurity and cyberphysical threats. Key vulnerabilities can be man- aged through the use of risk management and rule compliance measures (Hopkins 2011; ABS 2016). The response to such threats has included comprehensive guidelines that define procedures for implementing electronically secure systems. 11 Although these control systems were designed with an air gap, in reality, over time, many of these systems were linked to Internet-facing systems. 12 An overview of Stuxnet is available at http://spectrum.ieee.org/telecom/security/the-real-story -of-stuxnet/. 13 http://www.bbc.com/news/technology-30575104. 14 http://www-03.ibm.com/security/data-breach/. 15 https://www.abiresearch.com/whitepapers/petrosecurity-in-the-digital-era/. 16 http://www.pwc.com/us/en/increasing-it-effectiveness/publications/assets/pwc-2014-us-state -of-cybercrime.pdf.
Benefits of and Considerations for Remote Real-Time Monitoring 67 The guidelines apply to the many stakeholders, including end users and OEMs, who design, manufacture, implement, or manage industrial control systems. The guidelines include the International Society of Automation (ISA) and the International Electrotechnical Commission (IEC) 62443 set of standards and other documents,17 which describe the elements needed for a cybersecurity management system for industrial control systems and provide guidance on how to meet the requirements for each element. Extensive guidelines are also offered by the National Institute of Standards and Technology (NIST), including NISTâs Framework for Improving Critical Infrastructure Cybersecurity, which offers practical suggestions for cybersecurity.18 In a more controls-specific context, the Norwegian Oil Industry Association (Oljeindustriens Landsforening or OLF) provides recommended guidelines for information security baseline requirements for process control systems (see OLF 2009).19 MODUs feature systems that are Internet-capable, which increases demands for instrumentation of offshore equipment and for transmitted data, connectivity, and bandwidth from offshore. As more RRTM of offshore operations is introduced, the cybersecurity risks associated with the technology rise. Recently, the U.S. Coast Guard (USCG) released its cyberstrategy,20 which outlines its plan to work with industry and to manage cyberrisks to maritime-critical infrastructure. A final USCG policy is expected in 2016. The International Association of Drilling Contractors (IADC) Cybersecurity Taskforce is scheduled to release draft guidelines in 2016. They are based on ISAâIEC and NIST standards that will emphasize a risk assessment methodology (Hsieh 2015). Although BSEE is collaborating with USCG on cybersecurity issues, the agency has not released an official cybersecurity policy. The broader introduction of RRTM to offshore operations heightens cybersecurity risks for the industry and makes their evaluation more critical. 17 https://www.isa.org. 18 http://www.nist.gov/cyberframework/. 19 https://www.norskoljeoggass.no/en/Publica/Guidelines/Integrated-operations/104-Recommended -guidelines-for-information-security-baseline-requirements-for-process-control-safety-and-support -ICT-systems/. 20 USCG Cyber Strategy is available at https://www.uscg.mil/seniorleadership/DOCS/cyber.pdf.
68 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations RRTM and Human Factors Considerations from the National Aeronautics and Space Administration Research on human factors is diverse and multidisciplinary. It tradi- tionally includes areas such as ergonomics, cognitive factors, and orga- nizational factors, all of which can influence work design, resilience, operations, and safety. The following section is intended to present several examples of human factors from the National Aeronautics and Space Administration (NASA) that are relevant to RRTM of offshore oil and gas operationsâspecifically, the development of communication protocols. As more data are shared, the need to focus on communication protocols and the interactions of human actors grows. NASAâs experi- ence indicates the importance of incorporating human factors princi- ples through better communication protocols, which can often lead to improved shared situational awareness and team collaboration. The importance of communication protocols and team collaboration is supported by human factors research. For example, Salas et al. (2005) identified five central components of teamwork: leadership (ability to direct and coordinate activities), mutual performance monitoring (ability to understand and monitor team environment), backup behav- ior (ability to anticipate and shift workload among the team), adaptability (ability to adjust strategies on the basis of input or changing conditions), and team orientation (prioritize teamâs goal over individualâs goal). In addition, the authors suggest that these core components of teamwork are facilitated by the three coordinating mechanisms of shared mental models (i.e., common understanding of responsibilities and procedures), closed-loop communication (i.e., standard exchange of information between team members), and mutual trust (i.e., expectation that team members will perform roles accordingly) (see Salas et al. 2005). Over the course of its study, the committee visited several RRTM facilities for offshore drilling in the Houston area, including those of Shell, Chevron, Anadarko, Schlumberger, and BP. In all cases, the dis- cussions reinforced the view that human factors, organizational culture, and interpersonal relationships were key elements in the success of the RRTM operation. The visits illuminated many of the subjects discussed by industry representatives during the committeeâs April 2015 workshop (see TRB 2015).
Benefits of and Considerations for Remote Real-Time Monitoring 69 In addition to the RRTM centers above, the committee toured NASAâs Johnson Space Center and Mission Control for the International Space Station (ISS) to gain a slightly different perspective on remote real-time centers. Although this facility serves a command and control function as well as an RRTM function, some lessons from the NASA visit illustrate issues in offshore drilling RRTM. As are hardware, software, and communications capabilities, human factors are critically important in the success of NASAâs operation. The first important element of human factors is a well-understood definition of roles and responsibilities that is determined and communicated to all parties. The responsibilities of the on-scene commander (known as the spacecraft commander) must be clearly defined. Similarly, the roles and responsibilities of the remote personnel and their management must be delineated. Training is required to ensure that all personnel understand roles, responsibilities, and the structure of the chain of command.21 The second important element is close interaction of the remote team demonstrating its support for the on-scene team. In its absence, inter- personal friction will impede the success of the operation. In particular, the on-scene personnel (i.e., NASAâs astronauts) must be convinced that the remote team adds value and is not merely monitoring to record operator errors. The interaction starts with face-to-face meetings between team members before the on-scene (crew or offshore) team departs. In most remote operations, situational awareness with regard to events at the scene is critical. Where the RRTM center is merely advisory or serves as a backup, maintenance of situational awareness is desirable but not mandatory. In these cases, offshore (on-scene) personnel can directly communicate, as time permits, with the RRTM center to establish the centerâs situational awareness. As functional requirements for the RRTM center grow, continuous situational awareness of the RRTM personnel becomes more important. Some U.S. operators have proposed that remote monitoring will allow functions to be taken off of the MODU and performed onshore by 21 An important concept for NASA in achieving proper training is crew resource management (CRM) training. More information on CRMâs application to oil and gas operations is provided by OGP (2014).
70 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations RRTM personnel. The NASA space flight experience requires that much of the monitoring of systems performance be completed remotely, given the small number of crew members on board the International Space Station (ISS) (or previous vehicles) and the inherent complexity of the systems in operation. The on-scene team is simply too small to monitor all critical functions at all times. In addition, the most important use of the on-scene spacecraft crew (or potentially the offshore MODU team) is to do the things that can only be done at the site. Offloading the monitoring of basic systems from the on-scene team to the ground (remote) person- nel has been a necessity of human space flight. This feature has driven an extensive protocol concerning standard instrumentation, including mul- tiple redundant instrumentation points measuring critical parameters. A process for determining whether a particular instrument is oper- ating correctly and the protocol to be followed after an instrument has failed is also standard. Maintenance of instrumentation, including correct calibration, is a strong feature required in RRTM of human space flight. These paradigms differ significantly from current offshore drilling prac- tice. Advanced practices concerning instrumentation and measurement will be critical if primary responsibility for monitoring the operation of offshore equipment is to be moved onshore. However, as long as the RRTM function is merely advisory or a backup to the on-scene personnel, instrumentation requirements may continue to be less strict. Above all, clearly defining and communicating protocols for the roles and responsibilities for both offshore (on-site) and remote (onshore) teams are important for any offshore oil and gas RRTM endeavor. Proper training is required to ensure that all personnel understand roles, responsibilities, and the structure of the chain of command, especially to demonstrate the remote teamâs support of the on-site team. Maintaining situational aware- ness in the RRTM center is important but not mandatory as long as the center remains in an advisory or backup role. RISK ASSESSMENT AND RISK-BASED REGULATIONS As noted in Chapter 1, BSEE has sought to improve its offshore safety program by integrating RRTM technologies with an enhanced SEMS. Using more risk-based criteria would bolster BSEEâs risk-based regulatory
Benefits of and Considerations for Remote Real-Time Monitoring 71 program and allow the agency to prioritize which inspections and SEMS audits it should observe. The idea of risk-based regulation and inspection activities has been used by regulatory agencies for many years. It appeals to the simple intuition that inspections should be focused on facilities and operations where circumstances suggest that additional monitoring would be most effective. A risk-informed approach is used by identifying a hazardous event, determining its likelihood, and specifying its consequences. The expected risk is represented by the product of the likelihood and the con- sequences of an event and is often presented in the form of a matrix.22 These calculations can be used as an input to establish priorities for inspection and risk mitigation activities. The risk-informed regulatory and inspection approach is often fostered by identifying the adverse events that are the focus of the agency and is based on a series of steps that are carried out and revised on a continual basis. Such a process can take advantage of historical data that monitor and track events that could lead to oil spills or to fires and explosions. An example from Norway concerning how BSEE could integrate real- time or archived data into a risk-based approach is given below. BSEEâs recent risk-based initiatives are then reviewed, and opportunities with regard to RRTM applications in several of BSEEâs existing regulations are discussed. Norwegian Regulatory Practices The Petroleum Safety Authority (PSA) in Norway is often cited as a regu- lator that uses analyses of historical data to identify the most significant hazards. Its practices provide examples of how BSEE might integrate RRTM data into a risk-based regulatory approach.23 PSA has moved from prescriptive to more performance-based regulation (i.e., specification of the function to be performed and the performance to be achieved by the industry). PSA, like BSEE, found that prescriptive compliance inspections could encourage a passive attitude among companies, who would wait for the regulator to inspect, identify issues, and explain how 22 For an example of a risk assessment matrix, see TRB 2008, Figure 2-5, p. 43. 23 A more detailed discussion of the structure of PSA Norway is given by TRB 2012, pp. 58â67.
72 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations the issues were to be addressed. Under the prescriptive approach, PSA was in some sense a guarantor that safety in the industry was adequate and assumed a responsibility that should have rested with the operating companies (PSA Norway 2010). With performance-based regulations, the responsibility for safety is explicitly that of the operator, which must ensure the safety performance of suppliers and contractors. PSAâs areas of focus, such as audits, are risk-based, as determined by a broad set of data and performance indicators. Data collected through RRTM could afford BSEE a similar opportunity to supplement its risk-based inspection pro- gram, as is discussed in more detail below. On the basis of dialogue and collaboration among industry, PSA authorities, and the workforce, major risks with regard to petroleum activity are identified and documented in an annual report known as the RisikonivÃ¥ i norsk petroleumsvirksomhet (RNNP). The RNNP has an important position in the Norwegian industry because it contributes to a shared understanding of risk developments and risk perceptions by indus- try, Norwegian regulators, and the workforce. The RNNP documents the development (history) of a set of defined hazards and accident conditions (DFUs). There is a focus on mitigating DFUs in advance or reducing their consequences. Risk mitigation or the reduction of consequences is often based on exploration of RTM data. The RNNP is supported by additional data sources, such as the Daily Drilling Report System, and operating companies are required to provide information (in XML and WITSML) on drilling operations on the Norwegian Continental Shelf. With these data, PSA can analyze key information about all current operations. Simi- larly, BSEE could realize the value of RRTM through closer examination of archived real-time data that are supported through additional data sources, such as IADCâs daily drilling report, as discussed in Chapter 2. Norwayâs regulatory regime focuses on the following areas: â¢ Risk. The RNNP provides risk trends on the basis of incident indi- cators, barrier data, interviews with key informants, seminars, field- work, and questionnaire-based surveys. This allows the regulator to focus on what needs attention. â¢ Performance-based regulation. The operators must choose the solu- tions they will adopt to meet official requirementsâthe industry is responsible for how risks are mitigated.
Benefits of and Considerations for Remote Real-Time Monitoring 73 â¢ Accountability. The operator has sole responsibility for safety. It must ensure the safety performance of suppliers and contractors and sup- port a no-blame culture. The RNNP report uses one or more risk indicators to measure the status of most DFUs, which are analyzed and reported each year. DFUs with a potential for causing major accidents include hazards such as the following: unignited hydrocarbon leak, ignited hydrocarbon leak, well incident or loss of well control, fire or explosion in other areas, com- bustible liquid, ship on collision course, drifting object, and collision with field-related vessel or facility tanker (see Figure 3-1). Many of these hazards have little to do with real-time data; however, the leading DFU category by far over the past 5 years is well incident or loss of well control. Over the same 5-year period, PSA has focused on the quality of barriers to mitigate the probability and to reduce the consequences of incidents. Thus barrier management and the bow tie concept are being used. A barrier is defined as technical, operational, and organizational elements that individually or together (a) reduce the possibility of occurrence of specific errors or hazards or (b) reduce or prevent damage if they occur. To ensure acceptable operations, PSA audits companies by using a risk-based approach. The audits are conducted by personnelâusually a team of two to eight peopleâfrom PSA with the necessary expertise and experience or from other institutions with the necessary expertise, such as external consultants or research and development organizations. The audit team inspects and discusses key documents, and the operator must demonstrate its compliance with the regulatory regime or condi- tions that govern its operations. Findings are posted on a website and distributed to all interested parties. Audits use various approaches and methods adapted to the particular areas of focus. For example, SINTEF (Stiftelsen for Industriell og Teknisk Forskning), in conjunction with the oil and gas industry in Norway, has developed a method known as Crisis Intervention and Operability. It consists of a checklist with best available practices and a set of scenarios that can be explored to verify that the established systems can handle normal and unanticipated incidents.24 As BSEE moves toward a risk-based 24 More information appears at http://www.criop.sintef.no.
Number of DFU Occurrences 0 20 03 20 04 20 05 20 06 20 07 20 08 20 09 20 10 20 11 20 12 20 13 20 14 Ev ac ua o n or m us te r D am ag ed s ub se a in st al la o n Su bs ea e qu ip m en t l ea k St ru ct ur al d am ag e Co lli si on b y aÂ en da nt v es se l D ri Â in g ob je ct Sh ip o n co lli si on c ou rs e O th er fi re o r ex pl os io n W el l i nc id en t Ig ni te d hy dr oc ar bo n le ak U ni gn ite d hy dr oc ar bo n le ak 2040608010 0 12 0 FI G U RE 3 -1 R ep or te d oc cu rr en ce s of D FU s by c at eg or y. ( So u r c e : P SA N or w ay 2 01 5, 1 7. )
Benefits of and Considerations for Remote Real-Time Monitoring 75 approach, Norwayâs experience illustrates how data collection can assist in identifying risks and could inform BSEE in many of these practices. BSEE and Risk-Based Initiatives As mentioned in Chapter 1, BSEE has sought to bolster its risk-based regulatory program over the past 3 years by identifying or implement- ing initiatives such as a near-miss and failure reporting system, risk-based inspections, and RTM of offshore facilities.25 BSEE expects that these initia- tives will help improve management of many of the risks associated with and provide additional oversight of offshore oil and gas development. To enhance its capabilities, BSEE is pursuing a voluntary near-miss and failure reporting system26 developed in cooperation with the U.S. Department of Transportationâs Bureau of Transportation Statistics. The system will provide confidential reporting for individuals with regard to near-miss events associated with oil and gas operations. BSEE has also developed a risk-based inspection methodologyâdeployed within BSEEâs regulatory programâthat would aid BSEE in creating performance indi- cators to conduct further analysis and could allow the agency to prioritize which inspections and SEMS audits it should observe (DOI 2015, 8â9). Announced in December 2015, BSEEâs pilot risk-based inspection pro- gram for offshore oil and gas facilities would complement the agencyâs existing inspections and audits to enhance the safety of offshore oil and gas operations. This approach would focus on the evaluation of risk factors related to the design, operation, and environmental characteristics of a facility that might be correlated with a higher probability of experienc- ing a safety-related incident.27 The objective of a risk-based inspection program would be to use the agencyâs inspection capabilities in a more efficient manner. BSEE is also reviewing the potential of RTM as a risk-based oversight technology. As discussed in Chapter 2, remote real-time data centers are in 25 D. Morris, BSEE, presentation to the committee, December 2014; and S. Dwarnick, presentation to the committee at the Houston workshop, April 2015. 26 More information appears at https://near-miss.bts.gov/. 27 http://www.bsee.gov/BSEE-Newsroom/Press-Releases/2016/Bureau-of-Safety-and-Environmental -Enforcement-to-Launch-Pilot-Risk-Based-Inspection-Program-for-Offshore-Facilities/, Dec. 7, 2015.
76 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations operation today, with some operating on a 24-hours-a-day, 7-days-a- week basis and with constant communication between the offshore plat- form and the onshore facility. Initially, these centers were established by industry in anticipation of efficiencies resulting from better well planning and execution and from access to expertise or other experienced personnel onshore. As suggested by many panelists at the committeeâs April 2015 workshop, RRTM can enhance operational safety in several ways. Among them are supplying additional onshore monitoring of real-time data and provid- ing offshore personnel with access to onshore expertise, especially during cri t ical operations (TRB 2015). Although RRTM adds a substantial cost to offshore operations, companies that have implemented such centers indi- cated that the benefits that such centers provide are worth the costs. The value of RRTM arises from the additional information it provides, which gives decision makers the opportunity to change a current operating decision or to learn in order to guide a subsequent operating decision. The value of RRTM for BSEE may also include increased efficiency for its inspection activities. The availability of monitoring informationâ whether in real time or archivedâat an onshore site may support the review of safety-related information by BSEE inspectors before their visits to offshore facilities. Such preparation could allow for better scheduling of inspectionsâprioritized on the basis of riskâand could allow inspectors to focus on riskier operations during the visits. The value of the archived data for learning does not necessarily depend on a remote link onshore for real-time data monitoring. RRTM and Existing Regulations Application for Permit to Drill Before it drills a new well, an operator must submit an Application for Permit to Drill (APD). The APD28 (Form BSEE-0123) and the supple- mental APD (Form BSEE-0123S) require information (see Â§250.1617 for a complete list) concerning the planned safety and environmental 28 BSEE Form BSEE-0123 is available at http://www.bsee.gov/uploadedFiles/BSEE/About_BSEE /Procurement_Business_Opportunities/BSEE_OCS_Operation_Forms/Form0123%20exp %202017%20for%20APD%20IC.pdf.
Benefits of and Considerations for Remote Real-Time Monitoring 77 protection features of the new well. The proposed safety features may depend on the perceived risks of drilling and operating the new well or wells. The permitting process involves a BSEE review of the submitted documents and information and includes a dialogue between the appli- cant and agency personnel before BSEE approval can be given. During this process, BSEE can judge whether the plan is deficient and request the submission of additional information, if necessary. The APD form (BSEE-0123) could be modified to include a new ques- tion about the monitoring of well parameters and well control equipment. Such a question about well monitoring would be related to performance and would allow the applicant to propose relevant uses of RRTM and to explain why the company is or is not using RRTM. It would also allow BSEE to challenge the applicantâs APD with regard to the use of RRTM and the specific operations and parameters that will be monitored. Such a scenario is plausible since BSEE-0123 was modified in 2014 to add a question relating to digital BOP testing. Safety and Environmental Management System Adopted in 2010 as a risk-based safety management system, BSEEâs SEMS plan is required to be submitted by all outer continental shelf (OCS) operators to ensure compliance with this program. SEMS is designed to be flexible, which would allow operators working in diverse OCS envi- ronments to address hazards differently on the basis of the perceived level of risk associated with an operation. The current SEMS regulations could be used by BSEE to encourage offshore operators to address the role of RRTM in their SEMS plans by allowing operators to determine the circumstances under which RRTM would be used. For example, the SEMS plan could describe the RRTM facility and the communication protocols to be used. If RRTM is incorporated into an operatorâs SEMS plan, BSEE inspectors could use the plan as a baseline to monitor these activities and to ensure that the operator carries out the plan consistently according to the SEMS specifications. A review of the SEMS Potential Incident of Noncompliance (PINC) List29 indicates that BSEE would have opportunities to consider RRTM 29 A complete list of SEMS PINCs is available at http://www.bsee.gov/uploadedFiles/BSEE/Enforcement /Inspection_Programs/SEMS%20PINC%20List.pdf.
78 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations applications that might allow enhanced worker safety, environmental safety, and the conservation of resources in the SEMS. For example, PINC S-202 reads as follows: Does the mechanical and facilities design information include as appropriate the P&ID [piping and instrumentation] diagram, electrical area classifications, equipment arrangement drawings, design basis for the relief system, description for the alarm system, description of the shutdown system, the interlock systems for fired equipment, well control systems, passive and active fire protection system, emergency evacuation procedures, and the cathodic system for corrosion issues? Authority: API [American Petroleum Institute] RP [Recommended Practice] 75 SECTION 2.3.1 Enforcement Action: W/C/S [warning/component shut-in/ facility shut-in] 30 CFR 250.1916 INSPECTION PROCEDURE: Verify that the SEMS program has been developed and maintained, and includes written procedures that provide instructions to ensure the mechanical integrity and safe operation of equipment through inspection, testing, and quality assurance. The implementation of RRTM capability on the offshore facility, as documented in the SEMS plan, could enhance well control. Since no SEMS plan is appropriate for all facilities, this issue could be a topic of discussion between BSEE and an operator for operations in complex environments. If the SEMS plan did not include RRTM capabilities for a complex environ- ment, an operator would need to demonstrate that the plan met acceptable standards for well control capabilities without RRTM. The committee is not suggesting that RRTM capabilities would be considered a substitute for other system safety features, but instead that RRTM would be one of many safety features. Another PINC from this list could encourage a dialogue about risk management in the SEMS plan and could involve a review of an oper- atorâs RTM and RRTM capabilities. PINC S-200 addresses hazard identification: Does the SEMS program require that a hazards analysis be performed for the facility in order to identify and evaluate the likelihood and consequences of uncontrolled releases and other safety or environmental incidents? Authority: API RP 75 SECTION 3.1 Enforcement Action: W 30 CFR 250.1911, 1911(a)
Benefits of and Considerations for Remote Real-Time Monitoring 79 INSPECTION PROCEDURE: Verify that the management program requires that a hazards analysis be per- formed for any facility subject to this recommended practice and that human factors are considered in the analysis. The committee anticipates that many of these hazards would be evaluated with a matrix-based risk assessment as described earlier. Sub- sequently, PINCs, such as S-402 below, could focus on corresponding risk mitigation actions that might be enhanced by the use of RRTM. Have the findings of a current (initial or periodic) hazards analysis been presented in a written report that describes the hazards identified and the recommended mitigation actions? Authority: API RP 75 SECTION 3.6 Enforcement Action: W 30 CFR 250.1911(a) INSPECTION PROCEDURE: Verify that the lessee has identified the findings of a hazards analysis in a written report and that they have identified the recommended mitigating actions taken to correct the deficiency. In addition, contractor capability and selection are important to the overall safety of OCS operations, as emphasized in PINC S-703. Does the SEMS program document contractor selection criteria? Authority: API RP 75 SECTION 6 Enforcement Action: W 30 CFR 250.1914 INSPECTION PROCEDURE: Verify that when selecting contractors, operators should obtain and evaluate information regarding a contractorâs safety and environmental management policies, practices, and past performance along with their procedures for selecting sub-contractors. This aspect of the SEMS plan could be used to review the RTM data collection capabilities of a contractor, as well as the potential communi- cation links between the contractor and the operator. In the same spirit, PINCs S-900 and S-901 address the quality and mechanical integrity of critical equipment issues related to design, instal- lation, inspection, and testing. A risk-based evaluation of the SEMS plan in these areas could include plans for monitoring of critical equipment
80 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations that could depend on RTM or on RRTM to meet safety and environmen- tal goals. The committee reaffirms that any risk management plan is an active document that requires continuous monitoring, reassessment, and reaction. POTENTIAL OF CBM AND RRTM As stated earlier in this report, CBM, also known as predictive mainte- nance, is an approach to scheduling maintenance actions that are based on the condition (measured or predicted) of the component being maintained, as opposed to replacing a component at a scheduled time or time interval regardless of the actual condition. The following section discusses opportunities for the oil and gas industry to move from interval- based maintenance of critical safety equipment to a CBM model. Opportunities for Automation In a 2012 paper, GE described its corporate strategy of implementing the concept of an industrial Internet delivered in three progressively higher stages of intelligence: intelligent devices (where data on the condition of the various components making up a system are collected), intelligent systems (which can be in the form of an optimized network or optimized maintenance based on the collected component data), and intelligent decisioning (which occurs when âenough information has been col- lected from the devices and systems to facilitate data-driven learning, which in turn enables a subset of machine and network-level operational functions to be transferred from operators to secure digital systemsâ) (Evans and Annunziata 2012, 12). GE has proposed to develop this con- cept and apply it to a number of the sectors in which the company pro- vides devices, systems, and services, such as aviation, health care, and oil and gas production. For example, Iansiti and Lakhani (2014) state that by 2011, along with sensors and microprocessors, GE had significant embedded software running power plants, jet engines, hospitals and medical systems, utility companies, oil rigs, rail and other industrial infrastructure worldwide. Con- necting the hundreds of thousands of GE devices to one another and arming them with increasingly sophisticated sensors seemed like a logical extension of the maintenance-and-operations model.
Benefits of and Considerations for Remote Real-Time Monitoring 81 Before the intelligent decisioning functionality (i.e., significant auto- mation) can be envisioned, the intelligent device functionality (i.e., CBM) must be delivered. The potential for CBM clearly exists, and progress is being made in some sectors such as transportation, but even this sec- tor is still in the early stages of broad implementation of CBM based on predictive models. Aviation norms, procedures, and maintenance philosophy are rooted in time-tested, interval-based maintenance. Most mission- and safety-critical industries, including the oil and gas industry, operate on time-based or interval-based maintenance models. To move toward CBM, a dense set of data must be collected and accessed from the equipment to be maintained, which is well beyond the state of practice in the oil and gas industry. A move toward CBM would require invest- ments during equipment design and MODU construction. To deliver effective performance baselining, a dense data set with high standards of data quality is needed from the beginning of service for a piece of equip- ment. To achieve system-level CBM, several generations of equipment will need to be designed and delivered into service, which could take up to a decade. Equipment and process monitoring from onshore centers has already taken root in the industry, and onshore monitoring centers could serve as an early step toward achieving true system-level CBM. The data collected from equipment and monitored from these onshore centers are operational in nature and may not be useful for CBM. Ret- rofitting of current equipment to collect condition data is an important intermediate step toward true CBM. Given the variation of equipment (e.g., rotating, nonrotating) and industryâs reliance on fit-for-purpose engineering (e.g., no two MODUs are identical), achieving system-level CBM will prove challenging and time-intensive. However, component- level CBM for risers, on-deck rotating equipment, BOPs, and pumps are all promising candidates for early adoption.30 Industry may not be able to achieve equipment CBM sooner because of a combination of three factors: lack of skills and expertise in applying CBM approaches, data access and data richness or quality challenges 30 Diamond Offshore and GE Oil and Gas entered into an arrangement similar to a performance- based or uptime model, under which GE takes ownership of the BOP and is accountable for its performance. See http://www.oedigital.com/component/k2/item/11571-diamond-ge-ink -performance-based-bop-deal.
82 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations (Terranova 2015), and maintenance norms (i.e., method and philosophy). However, an opportunity exists for advancing CBM approaches in the oil and gas industry through incentives and collaboration. The data collected from such initiatives as remote inspection of equipment could be used to verify recommendations arising from CBM. (See Figure 3-2.) Even if equipment- and system-level CBM can be delivered, achiev- ing intelligent decisioning or automation in the offshore context will present additional challenges. Among them are delivering data access (transmission, security, richness, and quality), defining response options to detected fault conditions, and achieving situational awareness. Deliver- ing reliable automated decision support will also entail more testing cycles. Potential Predictive Software Issues Predictive software and data analytics have already reached levels capable of achieving CBM in other sectorsâfor example, aircraft and locomotive engines and wind turbines.31 However, the mission-critical equipment involved in offshore oil and gas operations is often engineered fit for 31 For examples of CBM in other sectors, see http://www.fastcompany.com/3031272/can-jeff-immelt -really-make-the-world-1-better. RRTM for asset availability and operaonal efficiency RRTM for safety CBM for safety CBM for asset availability and operaonal efficiency Industry (through API/IADC/IPAA/NOIA/OOC) + BSEE (through ETAC/OESI) sets CBM vision and targets through standing commiÂee on standards Industry Starng Point and Incenve BSEE Aspiraon BSEE Aspiraon Industry Goal Crical Enabler FIGURE 3-2 Developing CBM through RRTM (ETAC = Engineering Technology Assessment Center; IPAA = Independent Petroleum Association of America; NOIA = National Ocean Industries Association). (Source: Generated by the committee.)
Benefits of and Considerations for Remote Real-Time Monitoring 83 purpose. Thus, each companyâs equipment has its own engineering and manufacturing backgrounds. This implies a need for detailed information about and understanding of the equipmentâs intended behavior to deter- mine correlations with the data collected. For prediction of impending conditions, as opposed to recognition of the existence of a condition, higher-fidelity data capture is often required to build signature libraries of condition precursors by using acoustic, vibration, or other significant parameters. Higher-fidelity data capture will need to be considered during the equipment design cycle (e.g., for sensor placement) and during testing cycles (e.g., for the building of signatures). Predictive softwareâbased modeling (correlation analysis, data compu- tation, and algorithm development) is strongly dependent on designing CBM into the entire product plan and life cycle. CBM will require sophis- ticated sensors and sophisticated testing to determine ideal sensor location for detecting the signatures of condition precursors. In addition, the following issues will need to be considered during all phases of the equipment life cycle if industry is to perform predictive maintenance: â¢ Practice of a high level of data hygiene throughout the equipmentâs lifetime, which could be 30 to 40 years; â¢ Continuous (or thick) data, such as vibrations, which tax data networks much more than discrete data, such as temperature, oil pressure, or chip count; â¢ Availability of data science expertise so that the latest and most appro- priate data analytic approaches can be applied; â¢ Better baselining for equipment time in field and cycle counts; â¢ Collection and stewardship of detailed asset management life-cycle records; and â¢ Recertification of equipment, in the case of retrofitting, which often can be provided only by the OEM. Potential Hardware Issues To deliver CBM for the oil and gas industryâs equipment, a number of hardware issues will need to be addressed. Because many pieces of equip- ment may be inaccessible and in a harsh environment, they will need the ability to self-calibrate and operate at high temperatures and pressures,
84 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations and they will need to demonstrate a track record as in other industries with similar conditions. With an increase in the number of testing cycles and the baselining of equipment, more data will need to be captured, stored, and managed over the life cycle of the asset, which has implica- tions for the data storage capabilities designed into the equipment. To achieve system-level CBM capability on the MODU, a complete history of the condition of each piece of mission-critical equipment will need to be collected and maintained. This is known as a digital twin. The test facilities for this equipment, along with the sensing and data collection hardware, will need to simulate the real-world conditions in which they operate more closely. The costs of the design and testing of this equip- ment will likely need to be shared among OEMs and exploration and production companies. Finally, enhanced inspection capabilities will be needed to verify what the integrated sensors report. Model-Based Workflows Drilling and production operations are complex and require extensive planning. The challenge for many operators and service companies is executing a drilling or production plan while retaining the flexibility to respond to unanticipated conditions. In addition, interoperability of all actors and processes is critical. Enhanced data and new technology developments are increasing the availability of model-based workflows. Analytics to help in decision making are another interesting area of technology development. Smart algorithms, case-based reasoning tech- niques, machine learning algorithms, and science-based modeling process- ing flows all are bringing data-driven aids to decision makers, both offshore and onshore. Most of these solutions are still at the early stage of develop- ment and evaluation, and few operators will depend on automated decision making, except for safety-based processes. Decision-making responsibility still lies in the hands of experienced staff, mostly located offshore. SUMMARY DISCUSSION This chapter examined the implementation of RRTM technology in the context of BAST and suggests that RRTM could become widely available to industry and a part of its tool kit. The committee is not suggesting that
Benefits of and Considerations for Remote Real-Time Monitoring 85 RRTM be mandated on all wells, but instead that the implementation of RRTM as BAST could be considered relative to its potential contributions to overall safety, consistent with the principle of ALARP, where practica- bility is interpreted as encompassing both technological availability and economic feasibility. The chapter provides four examples of the notional benefits of applying RRTM in the areas of well integrity and early kick detection, augmented competencies from onshore, BSEE regulatory oversight and inspections, and CBM of critical equipment. With the increased availability of real-time data to onshore facilities, onshore crews can provide more assistance in monitoring real-time data. As companies establish roles and responsibilities and develop communication protocols, RRTM allows additional onshore staff to support offshore decision making and provides quick access to and collaboration with onshore expertise. BSEE is in a position to leverage archived RRTM data to support the more risk-based regulatory program that it has adopted. Deploying a greater array of sensors and enabling the aggregation of the generated data from equipment and assets across the entire fleet are both important for CBM. RRTM is effective in enabling the transfer of offshore data to onshore facilities and in allowing empirical data to be used in predictive modeling and, ultimately, CBM. As sensor technology advances and as the ability to transmit that data improves, data management issues involved with the use of real-time data will likely become more important. Increased use of RRTM of offshore operations and equipment will place new demands on the instrumentation of drilling and production equipment. Control systems for mission-critical rig-based equipment were not originally designed for connectivity back to Internet-facing systems and are not necessarily designed to be resilient to computer-based incidents that could corrupt or alter software. As more RRTM of offshore operations is introduced, the cybersecurity risks asso- ciated with the increased use of technology will rise. RRTM could benefit BSEE in some of its inspection activities by offering increased efficiency. Monitoring informationâwhether in real time or archivedâcould support the review of some safety-related information by BSEE inspectors before their visits to offshore facilities. Preparation could allow for more efficient scheduling and more effective execution of inspections, which would be prioritized on the basis of risk.
86 Application of Remote Real-Time Monitoring to Offshore Oil and Gas Operations BSEE could use existing regulations, such as SEMS, to manage the use of RRTM. By encouraging offshore operators to address the role of RRTM in their SEMS plans, BSEE could allow operators to determine the cir- cumstances under which RRTM would be used. Operational data collected from much of the equipment and currently monitored by onshore centers may not be useful for CBM, although collection of more conditional data is a first step. To move toward CBM, a dense set of data must be collected and accessed from the equipment or asset to be maintained, which may be beyond the current state of practice in the oil and gas industry and not attainable in the short term. Predic- tive softwareâbased modeling of equipment will require sophisticated sensors and testing to determine ideal sensor locations for detecting the signatures of condition precursors. More data will need to be captured, stored, and managed over the equipmentâs life cycle. Hardware issues also will need to be addressed, since equipment may be inaccessible and in a harsh environment. REFERENCES Abbreviations ABS American Bureau of Shipping BSEE Bureau of Safety and Environmental Enforcement DNV GL Det Norske Veritas and Germanischer Lloyd DOI U.S. Department of the Interior NAE National Academy of Engineering NRC National Research Council OGP International Association of Oil and Gas Producers OLF Oljeindustriens Landsforening (Norwegian Oil Industry Association) PSA Petroleum Safety Authority TRB Transportation Research Board ABS. 2016. Guidance Notes on the Application of Cybersecurity Principles to Marine and Offshore Operations, Volume 1: Cybersecurity. Feb. http://ww2.eagle.org/content/dam /eagle/rules-and-guides/current/other/221_Guidance_Notes_Cyber_Safety_Principles _Maritime_Operations/Cyber_Security_v1_GN_e.pdf. BSEE. 2014. Summary of BSEEâs 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.
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