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As SPE's Distinguished Lecture series wraps up its SPE section presentations for 2020–2021, a new series of virtual presentations stretches through the summer, providing access for all SPE members. Three of the live virtual presenters will be speaking on topics in the health, safety, environment, and sustainability (HSES) discipline. Each year, SPE selects industry experts, nominated by their peers, to share their knowledge and expertise at SPE section meetings. Despite the many challenges faced this season, SPE's Distinguished Lecturers gave more than 450 virtual presentations to members in more than 191 SPE sections countries around the world. Starting on 22 June, 22 presentations will be made available live virtually, broadening the audience from SPE section meetings to all of SPE's membership.
Abstract Recently, flood kill applications have been evaluated to cure blowouts due to gas migration from behind the casing while keeping the well integrity intact for further production. Traditionally, deterministic evaluations are used in planning these operations, ignoring the uncertainties in the characteristics of the gas sources behind the casing. This work focuses on using reservoir simulation-based workflow to evaluate the uncertainty providing probabilistic operating conditions to control the gas rates coming from behind the casing. The results of the simulations are combined to provide general guidelines for performing an effective flood kill operation. The studied parameters are divided in different categories based on their influence/impact on the effective kill. For example, the relationship between the best relief well position and reservoir permeability and anisotropy are studied, and the guidelines for the definition of the best location is identified. Based on the results of the analysis, the optimum required proximity of the wells can be determined. The analysis identifies the main factors for a successful flood kill operation. The situations where flood kill could be beneficial are identified and the success rate could be evaluated. This paper presents a methodology and guidelines for the design of an effective flood kill application. This methodology will help in positioning of the relief well and provide required control mechanisms to increase the chances of a successful operation. The methodology also provides insight on the required operating parameters, such as pump rates and total volume to be injected, for the operation to be successful. In addition, the developed workflow can be updated as more information is gathered while drilling the relief well. This will help in improving the chances of a flood-kill operation while providing tighter controls on the operational conditions.
Oilfield disasters shine a light on industry shortcomings. Below are three of the infamous events in industry history and the changes to equipment, procedures, and culture that have since been made to prevent their recurrence. What happened: In 1909, Julius Fried, a grocer, purchased land in Kern County, California, and founded the Lakeview Oil Company. In March 1910, after months of unsuccessful drilling that forced the sale of a controlling stake to Union Oil, oil struck at 2,200 ft. While running a bailer, the workers heard and felt a rumbling from under the well. What followed was the world's largest oil spill on land.
On 20 April 2010, a kick and blowout in the Gulf of Mexico resulted in a series of explosions that killed 11 people and started an environmental disaster. Now, 11 years later, government and industry continue the drive to improve safety. The disaster at Macondo Prospect resulted in the largest environmental catastrophe in the Gulf of Mexico; the US government estimates that 4.9 million bbl of oil spilled into the Gulf. Investigations after the disaster led to several safety initiatives from the industry and the identification of areas of improvement by government. To commemorate the date, the BBC has gathered some of those who were closest to the epicenter--those who worked on the rig or who worked so hard to staunch the flood of oil and clean up the disaster afterward--for an online program.
Key Takeaways This article describes the conversion of an acute care hospital into a dedicated COVID-19 treatment center at the beginning of the pandemic and details the safety and emergency management challenges and lessons learned. Among the lessons learned is that communication is essential, including collaboration between many departments and specialties. Also key are the active involvement and support of senior leadership in safety and health decisions, as well as the early involvement of community partners and resources. Finally, flexibility is needed without compromising employee safety and health. Beginning in March 2020, a 123-bed community acute care hospital was converted into a dedicated COVID-19 treatment center. Given the nature of the pandemic, the site conversion involved expanding intensive care capabilities from six to 70 beds, with an additional 88 general medical beds (Gold et al., 2020). Safety and emergency management remained a clear focus during the commissioning and operation of the COVID-19 treatment center. This article presents specific challenges, resolutions and overall key lessons learned for success in safety and emergency management. The unique ability to discharge all but one COVID-19 positive intensive care unit patient, discontinue for 1 week all patient-related services including emergency services and surgeries, and implement a preplanned concept of operations allowed for a successful transition and established the framework for the facility’s new mission.
Abstract Safety Critical Elements (SCEs) are the equipment and systems that provide the foundation of risk management associated with Major Accident Hazards (MAHs). A SCE is classified as an equipment, structure or system whose failure could cause or contribute to a major accident, or the purpose of which is to prevent or limit the effect of a major accident. Once the SCE has been ascertained, it is essential to describe its critical function in terms of a Performance Standard. Based on the Performance Standard, assurance tasks can be stated in the maintenance system to ensure that the required performance is confirmed. By analyzing the data in the maintenance system, confidence can be gained that all the SCEs required to manage Major Accidents and Environmental Hazards are functioning correctly. Alternatively, corrective actions can be taken to reinstate the integrity of the systems if shortcomings are identified. This paper shall detail out how the MAH and SCE Management process is initiated to follow the best industry practices in the identification and integrity management of major accident hazards as well as safety critical equipment. The tutorial shall describe in detail the following important stages:Identification of Major Accident Hazards Identification of Safety Critical Equipment, involved in managing Major Accident Hazards Define Performance Standards for these Safety Critical Equipment Execution of the Assurance processes that maintain or ensure the continued suitability of the SCE Equipment, and that these are meeting the Performance Standards Verification that all stages have been undertaken, any deviations being managed and thus that Major Accident Hazards are being controlled. Analyze and Improve Through the diligent application of these stages, it is possible to meet the requirements for MAH and SCE Management process giving a better understanding and control of risks in the industry.
Abstract In the event of offshore oilfield blow-out, real-time quantification of both spilled volume, recovered oil and environmental damage is essential. It is due to costly recovery and restoration process. In order to develop a robust and accurate quantification, we need to consider numerous parameters, which are sometimes tricky to be identified and captured. In this work, we present a new modeling technique under uncertainty, which accommodates numerous parameters and interaction among them. We begin the model by identifying possible parameters that contributes to the process: grouped into (1) subsurface, (2) surface and (3) operations. Subsurface e.g. well and reservoir characteristics. Surface e.g. ocean, wind, soil. (3) Operations e.g. oil spill treatment blow-out rate, oil characteristics, reservoir characteristics, ocean current speed, meteorological aspects, soil properties, and oil-spill treatment (oil booms and skimmers). We assign prior distribution for each parameter based on available data to capture the uncertainties. Before progressing to uncertainty propagation, we construct objective response (amount of recovered oil) through mass conservation equation in data-driven and non-intrusive way, using design of experiment and regression-based method. We propagate uncertainties using Monte Carlo simulation approach, where the result is presented in a distribution form, summarized by P10, P50, and P90 values. This work shows how to robustly calculate the amount of recovered oil under uncertainty in the event of offshore blow out. There are several notable challenges within the approach: 1) determining the uncertainty range in blow-out rate in case of rupture occurs in the well, 2) obtaining data for wind and ocean current speed since there is an interplay between local and global climate, and 3) accuracy of capturing the shoreline geometry. Despite the challenges, the results are in-line with the physics and several recorded blow-out cases. Define what is blow out rate (important as has highest sensitivity). Through sensitivity analysis with Sobol decomposition (define this …), we can define the heavy hitters. These heavy hitters give us knowledge on which parameters should be aware of. In real-time quantification, this analysis can provide an insight on what treatment method should be performed to efficiently recover the spill. We also highlight about the sufficiency of the model to obtain several parameters’ range, for example blow-out rate. The model should at least capture the physics in high details and incorporate multiple scenarios. In the case of blow-out rate, we extensively model the well completion and consider leaking due to unprecedented fractures or crater formation around the wellbore. We introduce a new framework of modeling to perform real-time quantification of offshore oil spills. This framework allows inferring the causality of the process and illustrating the risk level.
Abstract Subsea blowout preventer (SBOP) reliability is a major challenge in Deepwater Drilling & Completion operations, accounting for one of the major equipment failures and Non-Productive Time (NPT) costs yearly. This paper focuses on SBOP technological advancement since the Deepwater Horizon/Macondo incident in 2010, with additional emphasis on reliability, equipment condition monitoring and statistical root cause analysis. After finishing a deepwater well, the SBOP must undergo maintenance, repair if needed and pressure testing before being deployed on the next well. The rig owner is under great pressure to complete this turn-around to avoid waiting time. On an average, in-between wells, rig contractor took approximately 2.6 days extra time (NPT) waiting after completing top hole to get ready to deploy SBOP during 2019-20 exploration and appraisal campaigns. This can be critical during development campaigns where number of rig moves are involved quickly or in cases where top holes are batch drilled the waiting time for SBOP readiness can be as high as 7-8 days per well. Some operators are collaborating with drilling contractors in number of ways to arrange for a second fully assembled and (offline) pressure tested SBOP to be available on the rig (Dual SBOP); deployment of additional trained subsea engineers for performing maintenance/repair. SBOP pressure-testing time can also be drastically reduced by using comparative pressure-testing software to eliminate human error and accelerate pressure testing. Furthermore, leak detection time can be eliminated by installing sensors, and real-time test monitoring providing increased reliability with the additional advantages that conditional monitoring can be enhanced with the same digital sensors. SBOP dashboard that simplifies existing diagnosis and allow remote monitoring of the subsea SBOP control system will improve communication of SBOP health also serve common platform across rig fleets that allow standardization of SBOP diagnostic data and aids in operational decision making Ensuring additional SBOP redundancy especially while operating Emergency Disconnect System (EDS) available through Remotely Operated Vehicle (ROV) control panel or acoustic system. In addition, it is mandatory for the SBOP to have Autoshear and Deadman systems to be able to shut in the well in case of an emergency. Furthermore, technological workshop with several major service vendors have being held to ascertain current advances like Multifunctional profile, Accumulator recharged by ROV, ROV DP system, An Auxiliary Accumulator System and upgraded Acoustic System. In the end, the development of new technologies applied for the SBOP targets the overall cost optimization of the well lifecycle but also assure SBOP functionality. This paper is intended to provide considerations for operators in developing their future campaigns to frame scope of work for SBOP and rig contracting strategy.
Abstract The Snorre A blowout on well P-31 A on November 28, 2004, was a well control incident that sent percussions into our national and corporate HSE management systems. These percussions still resonate in our everyday work as a part of a comprehensive set of rules which encompass national regulations, industry standards, corporate functional, technical, or work requirements, as well as an integrated governing work process management system. Some of these rules have been embraced with a positive attitude and are now a natural part of our day-to-day work. They prepare for technical, organizational, and operational barriers that secure the safety of all personnel, shield the value of our investments and assets, and protect the environment. Some of these rules, however, may be perceived as dead weight and barriers in the sense of hindrances that may hamper an efficient workday and fill our agenda with many formal demands and obligations. This paper pinpoints and reviews "the change in rules" that the Snorre incident caused regarding planning, execution, and follow-up of drilling and well (D+W) operations on government, industry, and corporate level. The major failures that the investigations of the incident revealed have been handled diligently in our corporate system. In this paper, we track how management involvement, management of change, and "compliance and leadership" work in practice. The day-to-day tasks to prepare for safe D+W operations and to secure the integrity of wells in operations are explained. As an illustrative exercise, we are setting up a hypothetical plan for Snorre P-31 A as the D+W operations would have been planned today. This is done by outlining well barrier schematics, risk assessments, and the processes to handle deviations from technical or work requirements. Our objective is to explain that risk management in the planning and the execution of D+W operations and for wells in operations is coherent. To avoid the recurrence of incidents such as Snorre P-31 A, a systematic and rigorous approach is in use that makes it likely to capture inadequate well integrity conditions. This approach links high-end government regulations to sharp-end detailed operational risk management in our HSE management system.
Abstract The Deepwater Horizon accident is one of the major environmental disasters in the history of the United States. This accident occurred in 2010, when the Deepwater Horizon mobile offshore drilling unit exploded, while the rig's crew was conducting the drilling work of the exploratory well Macondo deep under the waters of the Gulf of Mexico. Environmental damages included more than four million barrels of oil spilled into the Gulf of Mexico, and economic losses total tens of billions of dollars. The accident brought into question the effectiveness of the regulatory regime for preventing accidents, and protecting the marine environment from oil and gas operations, and prompted regulatory reforms. Ten years after the Deepwater Horizon accident, this article analyzes the implementation of Safety and Environmental Management Systems (SEMS) as one of the main regulatory reforms introduced in the United States after the accident. The analysis uses the theory of regulation which takes into account both state and non-state actors involved in regulation, and therefore, the shift from regulation to governance. The study includes regulations issued after the Deepwater Horizon accident, particularly, SEMS rules I and II, and reports conducted by the National Academy of Sciences, the National Commission on the BP Oil Spill, the Center for Offshore Safety, the Chemical Safety and Hazard Investigation Board, and the Bureau of Safety and Environmental Enforcement (BSEE). The article reveals that though offshore oil and gas operators in the U.S. federal waters have adopted SEMS, as a mechanism of self-regulation, there is not clarity on how SEMS have been implemented in practice towards achieving its goal of reducing risks. The BSEE, as the public regulator has the task of providing a complete analysis on the results of the three audits to SEMS conducted by the operators and third parties from 2013 to 2019. This article argues that the assessment of SEMS audits should be complemented with leading and lagging indicators in the industry in order to identify how SEMS have influenced safety behavior beyond regulatory compliance. BSEE has the challenge of providing this assessment and making transparency a cornerstone of SEMS regulations. In this way, the lessons of the DHW accident may be internalized by all actors in the offshore oil and gas industry.