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. Through sensitivity analysis with Sobol decomposition, 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.

COMPANY-A is the operator of Field-A gas field that started operation in Country-A in 1996. Reliable and smooth condensate handling is key to ensure the continuous gas production and hence, maintaining the gas supply assurance. To cater for the reduced condensate throughput and export, COMPANY-A hired Company-B to refurbish a Floating Storage and Offloading vessel (FSO) named FSO-B; a new player and has minimum experience in oil and gas industry. Operation readiness review is crucial to ensure the safe operations in Field-A. In this paper, a review on the pipeline transient analysis and process safety focusing on condensate export line from SPM, flexible hose and piping modification on FSO-B is described as a showcase. The review that referred to API standard and internal PETRONAS Technical Standards (PTS) has contributed in determining the revised operating envelop of the SPM and FSO-B compared to the initial project proposal. The technical operation and design review resulted in the avoidance of potential loss of process containment (LOPC), production deferment and PETRONAS reputation as prominent gas supplier within the region. It is important to ensure that the operating envelop is suitable with the production profile. With the operational readiness exercises, FSO-B was designed correctly and ensured of safe operation. FSO-B was commissioned on time and started operation without much delay and hence, securing the gas supply of 60 MMSCFD from Field-A to Customer-C, and exporting up to 1500 BPD condensate smoothly without interruption. This exercise has contributed to safeguard the tangible value of maintaining the gas production as well as keeping the intangible value of PETRONAS reputation. The operational readiness especially on the pipeline transient analysis review is significant novel to be replicated in other similar operations in PETRONAS and in similar operations in other operators.

This paper describes a methodology that can be used to estimate the potential value of implementing digital and automation technologies in the well construction process in the context of a complex deepwater environment during the drilling conceptualization phase. This serves as a guideline for those interested in quantifying the value of applying digitization and automation processes, not only to make informed decisions related to investment in drillship or systems hardware and software but as well as performance improvement.

This paper focuses on the gas characteristics in caprock interval and the gas migration mechanisms from the carbonate reservoir into the caprock and its effects on caprock seal capacity. The workflow mainly includes three methods:(1) Gas geochemistry analysis from the GWD (Gas While Drilling) data to understand the gas composition, their distribution and mechanism for gas migration; (2) Petrophysical analysis to understand the rock types, petrophysical properties and the pore-throat system; and (3) Pore pressure prediction to understand the pressure sealing capacity of the caprock. Integrating the results from these three aspects, the sealing capacity can be evaluated by capillary pressure sealing, pore pressure sealing and the effects on the sealing efficiency for CO 2 . There are two gas migration mechanisms in the area: gas diffusion and gas advection. The gas in the caprock of Field A shows decreasing molecular weight trend from deep to shallow depths implying migration from the underlying carbonate reservoir by gas diffusion. However, the gas in the caprock of Field B where there is a gas chimney visible in the seismic data, has composition similar to the gas in carbonate reservoir, suggesting that the gas came from carbonate reservoir below by gas advection through faults and induced fractures and occurred simultaneously with the gas accumulation in the reservoir. There is also gas in the caprock above the gas chimney with lighter molecular weight representing gas that migrated from the gas chimney by gas diffusion. The caprock seal capability in the two fields are different. The gas in the carbonate reservoir in Field A can be sealed and trapped by the high displacement/entry pressure of the capillary pore-throat system and the abnormally high pore pressure in the caprock. The gas chimney at Field B would be connected to the carbonate reservoir below over geological time and there is effective seal enough to contain hundreds ft of gas column in the carbonate reservoir. The understanding of the leaking mechanism in these two fields is helpful for understanding the leakage scale, the effects on the sealing capacity, the risk evaluation and mitigation amendment.

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.

Following Tantawan field suspension of production, considerable volume of contaminated crude (high level of mercury and arsenic content) remains on board in Tantawan FPSO. These volumes are deemed as waste hydrocarbon sludge that hold no commercial value and must be urgently removed from the vessel as per safety requirements to maintain the vessel class and certification, according to Tantawan FPSO integrity condition. After review of many alternatives, offshore subsurface disposal initiative is the safest and most cost-effective means for disposal. Since subsurface disposal of such waste, highly mercury and arsenic contaminated crude, has never been performed in the Gulf of Thailand, several aspects need to be considered from technical and environmental perspective and public sector concerns. A cross functional team of Reservoir Engineer, Geologist, Facilities Engineer, Health and Safety, Policy, Government and Public Affair and commercial advisor, has co-devised a holistic waste management plan to inject waste into Tantawan reservoirs after obtaining required approvals by the government. Many challenges including limitation of the FPSO pumping system, sludge properties and seasonal increment weather, were encountered during the execution phase and many remedial actions were taken to mitigate their impact. Cross functional team initiatives on heater installation, adjusting injection procedure, and additional disposal well approval helped address project challenges. Entire volume of sludge was safely injected to subsurface reservoirs with cost effective operation. The success of this offshore injection process has reduced the cost to less than 10% compared to onshore disposal option to asset joint venture. The results set a new standard for Thailand petroleum waste management policy. Following this success, decommissioning of all remaining of Tantawan field are progressing as scheduled. This paper will outline the holistic approach of hydrocarbon sludge management process including the subsurface injection identifcation, stakeholder engagement, environmental impact assessment and execution challenges. Lessons learned from this paper would help other offshore operators to effectively manage hydrocarbon sludge, which demonstrate how the oil and gas industry plays a vital role in protecting the environment.

Malaysia's government recognizes the high risk that aging idle wells pose to its health, safety and environment and has developed some of the most stringent plug and abandonment, P&A, regulations to protect its future. Corroded casing strings and sustained casing pressure are common issues on its multi-decade old platforms and a risk-based design philosophy has been adopted to balance risk mitigation and operational costs, while still ensuring an eternal barrier. Both conventional rigs as well as rigless hydraulic workover units, HWU, are being used for P&A operations. This study considers the barrier element rationale applied in four offshore wells that were plug and abandoned by cap-rock restoration Perforate, Wash, Cement, PWC, barrier plugs. It also considers the operating window of a jet-based PWC technology to understand the challenges and opportunities for further optimization during HWU operations. Cap rock restoration utilizing both cup-based and jet-based PWC technology is being widely applied throughout Malaysia as a cost-effective alternative to casing section milled barrier plugs. Malaysia's P&A regulation allows isolation at the cap rock level, whereby "Contractor shall adhere to the Cap-Rock Abandonment Applicability Flowchart to identify technically and commercially acceptable candidates for this well abandonment method." The PWC method enables cap rock restoration in a single trip process; whereby the casing annulus is accessed by TCP guns to allow for annular debris to be effectively washed prior to cement plug placement. The process is not limited only to TCP guns; as a mechanical casing perforator was utilized in a shallow cased hole section of one of the wells to avoid damaging the outer casing. A custom BHA was developed and tested to match the cuts from the mechanical perforator. Specially oriented, rotating, wash jets were configured to maximize the annular access during the washing process. The washing effectiveness of this new BHA was confirmed by the massive amount of annular debris that was observed over the surface shakers. Operations were conducted offshore with a HWU with limited infrastructure and operating capability compared to a conventional rig. A PWC candidate screening matrix was applied early during the planning phase to manage rig limitation, well condition and operational risk to ensure successful barrier placement. All cap rock barriers were successfully installed and tested, and no sustained annular pressure remained in any of the wells. Fewer PWC plugs were required than originally planned, due to strict adherence to the Caprock Restoration Plan Decision Tree , resulting in significant cost savings for the project. The detailed time breakdown of the HWU operations provides useful insight into the operational efficiencies and unplanned events during the HWU campaign and lessons learned are shared from the project.

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.

Run-to-end (hereafter referred to "RTE") is a fit-for-purpose approach to manage late field life assets for realization of full potential through safe, reliable and cost effective operation by maximizing value at the end of economic life while complying to minimum technical standards through ALARP demonstration. RTE provides an overview of the multiple processes which shall be adopted and customized to the business needs of the intended facilities with the aim to minimize value leakage and ensuring safety until facility's cease of production prior to relinquishment or decommissioning. This RTE philosophy is to be applied to facilities that are within 5 years of its end of economic life so that value leakage can be minimized within the tolerable risk. The RTE provides an overview of development of case for change, guided process for the Operation & Maintenance philosophy changes and demonstration of risks mitigation & governance assurance. The safety risk of the facility shall be assessed and monitored through continuous ALARP demonstration. If the facility is deemed to be either no longer safe through ALARP or can no longer maintain a positive cash flow position, it is recommended that the facility to cease production operations and proceed with relinquishment or decommissioning activities. It has been implemented in one of late field life and resulting to 30% reduction of OPEX.

This paper reports on a project to develop a semi-autonomous snake robot, designed for entry into high pressure combustible gas systems. The project is funded by Innovate UK and is a collaboration between Process Vision and the University of Reading. Recent advances in robotics are making many inspection and maintenance tasks possible. The objective of the project is to provide a proof of concept prototype that can increase plant availability, by reducing the need for inspection shutdowns. As well as improving safety by reducing confined space working and reduce shutdown durations, as online diagnostics will help shutdown planning and logistics. If internal inspections could be performed without the need to shut down this would: Reduce downtime and increase efficiency in production Reduce OPEX Provide a safety benefit by reducing confined space working Provide an environmental benefit by reducing the gas sent to flare to de-pressurise Reduce fixed costs Allow fewer man hours in inspection tasks Remove the need for purge gas – nitrogen or air Reduce the number of procedures required Reduce the amount of paperwork

The Unconventional Resources (UR) Gas Operations has recently been developed to deliver the first unconventional production to its customers, to produce, process and pipeline gas to satisfy energy demand and support the potential future development, and reduce the liquid burning at power generation facilities. This organization handles unique, scattered and unmanned facilitates, where each facility operates differently based on the geographical nature of the field. For start-up, best practices were leveraged from for Unconventional Gas companies around the world. This includes reviewing and incorporating latest technologies to meet the business challenges of unconventional gas at the lowest cost, and most importantly, safest operations. As a new operating organization, UR Gas Operations had to define their major processes for achieving the objective of delivering customer expectations safely. These processes include the implementation of a Safety Management System (SMS) to enable control and management over plant safety, maintenance and reliability. With the help of advanced digitalization, SMS processes are being automated to maximize their effectiveness and efficiency. SMS acts as one platform that integrate the safety processes of different facilities under one umbrella. Furthermore, SMS is a critical pillar of Operational Excellence, it involves a set of defined processes that are measured through KPIs to comply with the company's safe operations which was named "SMS Online" Developing SMS Online have a positive impact on two key stakeholders in UR; Gas Operations Engineers, and Gas Operations Management. The SMS Online is a visualization platform for the safety performance KPIs across the UR Gas Operation organization. Hence SMS enforces accountability for proper KPI tracking and reporting, with compliance to safety processes. In addition, SMS Online creates an environment that supports engineers with their daily safety revisions, tracking, guidance, etc. This portal has increased the accessibility to safety processes across the organization by having a friendly user interface that navigates through SMS elements and processes. The system also provides an automated tracking system for assigning and managing action items assigned against individuals that alert actionees for closing an item prior to the deadline through an alerts and notification system. In a majority of the industrial facilities around the world, there is a big gap between building a new facility and being fully developed Business Operating Company. A comprehensive vision and a check list of essential Information Technology and Operational Technology systems was put in place to support business readiness for safe and efficient plant start up. SMS Online was a key component of this strategy, which was developed in-house by the UR IT as the first automated safety management system in the UR.

Eliminating fatalities and serious injuries amongst the workforce is of paramount importance of every Fatality Prevention policy or system. This abstract explores Best Practice of Save Your Life Actions / Start-Work Checks Fatality Prevention initiative with an ultimate objective of eliminating fatalities resulting from Human failure to safely execute work primarily by reducing Human-error rate. The initiative starts with Identifying and understanding risks of hazardous work activities of high potential consequences and safeguards to prevent or mitigate these consequences, then, developing two Human Performance tools to reduce human-error rate. The first, Save Your Life Actions, provides clarity on critical safeguards to improve ability to assure workforce knowledge and reinforce consistent execution. The second, Start-Work Checks, is a verification tool completed by a Start-Work Verifier prior to starting work and focuses on assuring that all critical Safe Guards are positively verified being in place and functioning immediately prior to work execution 100% of the time. After first year of implementation by an international oil company, these tools have not only contributed on exceeding all 2018 Workforce Safety milestones, they also contributed on marking a significant milestone, the first calendar year without a workforce fatality in its long history. The milestones of serious injuries have greatly improved as well. The monitoring, assessments and feedback of the initiative have shown enhancement in workforce's knowledge on the high potential consequence activities and critical Safeguards leading to clear reduction in human-error rate. As Fatality prevention is not a task that to be completed and left behind, continual improvement process identifies gaps and opportunities to strengthen and improve safeguards. This has clearly set the next step in this journey, that is introducing a Verification and Validation Coaching program. This program has the objective of enhancing workforce competency and confidence in application of safe work management system through on-site engagement by expert coaches with the front-line workers to closely observe work and provide feedback, anonymously, to workers. Pilots, already implemented in some upstream operations, have shown drastic improvements in both Human Performance and Safeguards Assurance measures. From a Human Performance perspective, Safety is not about eliminating incidents, but is about presence and functionality of Safeguards. People make mistakes and human-error rate is to be reduced when executing high potential consequence works by assuring and enhancing their knowledge and competency on critical safeguards. Implementation of such tools, Save Your Life Actions and Start-Work Checks followed by the Verification and Validation Coaching Program, will be highly beneficial to the industry towards Fatality Prevention.

In many Countries legislation forces Oil&Gas Companies to implement a Process Safety Management System (PSMS) to prevent and mitigate major accidents associated to the release of energy or hazardous substances. In plants where activities may have lower process risks, such as contaminated groundwater treatment plants, the implementation of a PSMS usually is not mandatory. This paper outlines how also these plants could benefit from a Process SafetySafety framework. A PSMS can be developed in line with the framework of an internationally recognized organization (CPPS, Energy Institute, IOGP, OSHA) to be applied to activities with significant HSE risks while it may be considered as an internal standard for low-risk activities. The effectiveness of the PSMS adopted and its correct and complete implementation in accordance with the selected framework may be evaluated by a dedicated audit protocol. The typical findings from audits carried out on reference upstream and downstream installations as well as on some low-risk plants were collected and performance compared in order to identify peculiarities in terms of good practices and recurrent areas for improvement. The main results of the benchmark are presented in this paper. The results confirm that the effectiveness of a PSMS is strictly linked with the level of risks in the activities and how such risks are managed both in administrative and operating processes. A robust risk-based approach in all processes, fostered by a visible commitments of top management, is the successful key for enhancing the Process Safety culture of personnel and ensuring safe performances and business continuity in operations, irrespective of the risk level in activities. The paper also provides a roadmap for implementing a PSMS in contaminated groundwater treatment plants, tailoring the Process Safety framework to the specific operative needs and risks.

Continuing development in the technologies of unmanned aerial systems or drones offer opportunities to the oil industry to make a step change to the way we manage safety and environmental risks. The use of drones can minimize exposure of personnel to dangerous environments, monitor the environment and enhance asset integrity. The SPE vision is to advance the oil & gas community's ability to meet the world's energy demand in a safe, environmentally responsible and sustainable manner. HSE or Health, Safety, the Environment and Sustainability are core values in the oil & gas industry. This paper reviews how the current and potential applications of drones in the oil industry can enhance safety and environmental aspects of oil and gas operations.

A pilot of cryogenic distillation technology is designed and installed for separation of the high CO 2 concentration of feed up to 80 mol % from natural gas. However, the main concern was the dry ice formation during depressurization or blowdown might cause the pipeline and equipment blockage and consequently resulting in safety issues. A dynamics simulation and modeling were conducted using commercialize software to determine the settle out temperature during the blowdown especially emergency condition. The investigations were focused on the high operating pressure and low operating temperature with a high CO 2 composition which is closer to transient condition and solid region. Then, more comprehensive modeling was conducted by incorporating the equipment and piping design data including the sizing of relieve valves (RVs) and blowdown valves (BDVs). The accuracy of information is very crucial to obtain more reliable results. It was observed that at high operating pressure, (50 to 75 barg) and low operating temperature,(-58 to 15 °C) the settle out temperature due Joule-Thomson (JT) effect were −58 °C and −92 °C for 60% and 80% CO 2 concentration, respectively. Based on the phase diagram, in this condition, the CO2 will be under a solid region. As a result, the Minimum Design Metal Temperature (MDMT) of −100 °C was selected for equipment and pipelines design to avoid material brittle-fracture. Few mitigations measure were designed and installed to avoid the CO 2 solidification. The BDVs were installed at the warmer area to minimize the JT effect leading to lower operating temperature than CO 2 solidification temperature resulting to potential equipment blockage. The electrical heat tracings were installed at the outlet flange and outlet line of RVs and BDVs to maintain fluid temperature above CO 2 solidification limit. This is to prevent CO 2 solid from attaching to the pipe wall and build up in the piping in the event of relief. Another mitigation was by installing the outlet line with sloped toward vent header and free from instrument probe or sensor to prevent CO 2 solid from build up at piping dead leg section. As a result, no sign of CO 2 solid found in the sections that equipped with mitigations measure during experiments. An inherently safer design of equipment and pipelines are very crucial especially for high CO 2 concentration, high operating pressure and low operating temperature with the appropriate mitigations to avoid catastrophic failure.

The limitations to performing rigless interventions in small platforms and safety concerns of performing multiple heavy lifts to the platform have motivated different locations worldwide to find solutions for accomplishing their objectives by utilizing proven techniques. In Brunei, after more than 8 years of continuous coiled tubing (CT) catenary operations, comprehensive and detailed processes have been strongly established and have created a guide that can be used for implementing similar operations in other locations that do not have such experience. A methodology was implemented to find the bottlenecks in each process involved during the entire cycle of a CT intervention as well as the actions taken by an operator and a service company to eliminate them. Statistical comparisons were used to contrast what was done in the past with what has been implemented in recent years. Additionally, new vessel positioning systems, improved disconnect systems, and proven safety considerations were analyzed, and a streamlined process to operation design, execution, and evaluation (DEE) cycles was developed. As a result of the process improvement documentation has been elaborated which include the flexibility and limitations of the system to cover concerns that are usually present in every stage of the intervention. Checklists and local guidelines will aid workers from other locations to implement catenary operations by using a reference document to cover HSE requirements and well integrity issues including volatile operating conditions and to obtain the information necessary to deliver technically challenging operations. This work supplements the current literature that addresses the "what" of past case histories by providing guidelines for the "how" to achieve an implementation of successful operations while complying with global HSE and environmental regulations. A priority of this work was sharing of knowledge obtained while giving space for continuous improvement related to this type of operation in the future.

There is an increasing trend in the oil and gas industry for the use of Enhanced Oil Recovery (EOR) techniques to improve the oil recovery from the reservoirs. The industry is well established to manage the hazards associated with hydrocarbon liquids and gases. However, polymer powder, used for Chemical EOR, presents a new set of hazards that needs to be incorporated into the HSE design of these facilities. This paper presents the main HSE design aspects to be addressed for the management of the process safety, environmental and personnel safety hazards introduced by polymer EOR facilities in the oil and gas industry. Total has conducted a number of Chemical EOR studies and implemented pilot plants, with an aim to developing full oil fields based on polymer flooding of the reservoirs. A comprehensive review of these polymer projects has been carried out and the HSE lessons learnt have been assessed. Information from polymer suppliers has also been reviewed, supported by an extensive literature review of the HSE requirements and standards for other powder handling industries. The review focused on the HSE design aspects for those polymer EOR projects that use powder as the source material. Hazards related to the handling of powder based products are effectively managed in other industries and documentation exists to guide designers on the requirements for managing these hazards in their processes. The use of polymer powder is not new to the oil and gas industry, however, very little guidance exists, to account for this hazard as part of the HSE design of the oil and gas facility, as it is less understood compared to the hazards presented by flammable oil and gases. An HSE guideline has been prepared to enable a better understanding of the hazards of using polymer powder in EOR facilities. The guideline serves as a bridge to facilitate the incorporation of this new hazard into an already established safety design management process. This paper presents the main HSE design aspects from this guidance document and addresses key areas such as flammability and dust explosion; area classification and ignition control; drainage and spill containment. The personnel safety requirements to protect the plant operators are also addressed.

This paper outlines the result of a design safety FLNG approach from research through concept development and ultimately implementation in design and engineering. Prevention of process safety events is critical to business success. The industry has been developing and improving all aspects of its FLNG design since the 1990s. Safety has been the primary focus in FLNG design. There has been a programme of work to ensure that the FLNG has been well designed and as a result the facility incorporates a number of proven and tested technologies that have been in use in existing LNG plants for many years. However, for FLNG, comprehensive design standards have not always been available and so research and risk assessment as well as guiding safety philosophies has been essential the process safety challenges for the conceptual development and design. In order to fully understand the risks associated with all aspects of a FLNG project and to manage the risks so that they are As Low As Reasonable Practicable (ALARP), it has been necessary to perform detailed safety studies to benchmark the safety of the facility and inform the risk mitigation in the design. This development has identified multiple robust and proven ‘barriers’ to prevent safety incidents happening on the facility. The primary strategy for minimizing the fire, explosion and cold spill risk focused on hazard prevention. Whilst this strategy reduced the probability of an uncontrolled loss of containment, there remained a risk, which required control and mitigation. The barriers have been embedded in our FLNG safety philosophies and implemented in the design. The industry is conscious that the prevention of process safety incidents is both critical to keeping people safe and also to ensuring continued business success. The extensive research that has been applied to this FLNG design provides confidence that the FLNG facilities will be as safe and reliable as other modern offshore production facilities currently in operation.

KOC has focused on Asset Integrity Management System (AIMS) & HSE Management System to enhance process safety & prevent Process Safety Management related incidents & spills. AIMS implementation in KOC facilities started a decade ago & KOC has developed a new PSM group in 2015 to focus on process safety while HSE Group has enhanced the personal safety system / standards / procedures. KOC strives to achieve sustainable Operations Excellence to ensure the followings: (1) PSM incidents are systematically analyzed to identify Root Causes & Critical Factors, (2) Key Performance Indicators (KPIs) are implemented with controls in place to prevent recurrence & monitor progress. The overall AIMS system comprises (1) well integrity, (2) pipeline integrity and (3) facility integrity with focus on PSM system at present. While the company's HSE management system is more focused on personal & occupational safety, environment protection & behavioural-based safety (BBS), the AIMS/PSM aspiration is to imbed inherent safety in the project design cycle, manage the safety critical equipment (SCE) and aim for sustainable Operations Excellence. Operational Excellence is at the heart of KOC commitment to HSSE and is integrated & not separate. It also includes a comprehensive Behavioral Based Safety (BBS) implemented in all assets to identify & correct the human error aspects which can emerge as critical factors leading to incidents. The AIMS system implementation commenced under HSE umbrella and is focused on process safety management system (PSM) with relevant policy and procedures. Company operational assets include Wells, Flow lines, Manifolds, Gathering Centres (GC), Booster Stations (BS), Pipelines corridors, Tank Farms, Export & Marine Facilities . Planned Preventive Maintenance (PM) and Inspection & Corrosion activities involve RBI (Risk Based Inspection) of static equipment and RCM (Reliability Centred Maintenance) for rotating machinery.

Among the strategic issues of the Oil & Gas Industry, management of well integrity currently plays a key role, since it allows to simultaneously achieve two major objectives: minimize risk of uncontrolled release of hydrocarbons and extend the life of wells, thus getting the most from reservoirs. Well integrity is about maintaining at least two independent well barriers at all times. This prevents reservoir fluids from being unintentionally and uncontrollably released at surface, and from migrating to other underground layers. However, degradation over time may weaken the elements comprising well barrier envelopes, and therefore impair well integrity if not taken into due consideration. This paper describes an innovative approach to well integrity, which effectively puts the concept of "proactive management" into practice: the aim is not only to ensure that wells operate safely today, but also to be reasonably confident that they will properly work in the future in order to achieve an extended production life and optimize operational expenditures. The subject approach complies with the ISO TS 16530-2 "Well Integrity for the Operational Phase", and uses both a failure mode analysis and a risk assessment technique to estimate the residual well life, on the basis of the expected degradation rate of well barrier elements. The described approach enables to: Evaluate the current well integrity status through a risk-based perspective Anticipate future well integrity issues Elaborate a suitable risk reduction action plan Identify proper monitoring and maintenance requirements. A dedicated software has been developed to effectively support the analysis of the current well integrity status and the identification of the well barrier elements that are expected to become critical in the future. The main characteristics of the software are also described.