This paper aims to encourage Front End Loading (FEL) to be used more effectively to increase the likelihood of delivering better project outcomes. It introduces a simple and pragmatic approach to assessing FEL which can be carried out in-house. Previous research has shown that, despite FEL being highly regarded, companies regularly sanction projects with insufficient levels of FEL. This has frequently resulted in projects not achieving the outcomes promised at the Final Investment Decision (FID) in terms of cost, time and production attained. This paper reviews reasons why FEL may not be used very effectively at present and proposes a solution to change this. An alternative method of assessing FEL has been developed which: is decision-based; can be carried out internally; and provides clarity on the factors that drive good FEL. In addition to assessing the status of activities carried out in the phase, the decision-based approach emphasises value-creation by considering key factors that could influence an increase or decrease in Decision Quality and thus the value created by the final outcome. The benchmarking and the decision-based approaches to FEL are very different. FEL benchmarking is external, objective, more bottom up; whereas the decision-based approach is internal, subjective and more top down. The benchmarking approach is more detailed, with a large number of individual activities assessed, and the progress on these aggregated to provide an overall benchmarking score. The decision-based approach is more of a big picture view. FEL benchmarking is well proven and its use is advocated. The decision-based FEL approach is unproven, but it has benefits that are not available from benchmarking and avoids some of the disadvantages. It encourages consideration to be given to activities that may result in value being created or destroyed; e.g. ensuring there are sufficient and appropriate alternatives during the Select phase, and that the benefits of flexibility are taken into account. A further advantage of the decision-based approach is that working through the FEL tools as a project team leads to a better joint understanding of the project and improves team integration. The two approaches consider FEL from different perspectives and have different benefits. They complement each other, and so the combination of the two approaches is more powerful than either on its own. It is suggested that the two approaches are worked in conjunction with each other to gain the benefits of both methods, provide a better understanding of FEL, and have a stronger basis for decision-making. A new way of assessing FEL has been developed which uses a decision-based approach aimed at increasing the value of project outcomes. Separate tools are provided for the Concept Select and FID phases.

This paper elucidates the key flow assurance challenges for China’s first National Deepwater gas field development in South China Sea and the facilities design forming the overall flow assurance management strategy. The discussion covers early stage feasibility studies through current stage of project execution. In addition, the finding of flow assurance analysis serves as key input for start-up and commissioning guidelines as well as operating procedures. The development consists of a semi-submersible, with the Eastern and the Western loops spanning more than 40 km of Subsea Production System (SPS). Due to long subsea tiebacks, integrated flow assurance analysis is rolled out to ensure comprehensive risks analysis and active risks management. In particular, key challenges associated with typical Deepwater characteristics such as high pressure and low temperature are actively managed. With design water depth of more than 1500 m and more than 10 Deepwater subsea production wells, robust flow assurance management strategy is required from early activities such as well unloading, well test, pre-commissioning, first gas, through late life decommissioning. Integrated approach is implemented for overall system thermohydraulics analysis, which is used as basis for key flow assurance assessments, including but not limited to management strategy for hydrate, scales, erosion, and slugging. Detailed management strategy and philosophy are discussed in the main body of this paper. Overall chemical management strategy, for instance, is fully optimized to reduce Health, Safety, Security and Environment (HSSE) impact, coupled with sufficient safety margin to ensure minimum downtime. Through integrated flow assurance analysis, all key risks are identified and actively managed. This shows the importance of integrated flow assurance approach to ensure overall project safety and integrity. More importantly, overall optimization can be successful rolled out when the field is in production. This serves as a positive lesson learned for future Deepwater development in South China Sea.

Mature facilities were previously built based on outdated code and standards which do not yet incorporate lessons from recent incidents. In order to have more robust plant safety management, plant design and Emergency Preparedness are upgraded incorporating new technologies. The selected upgrading methodology involves comparing the available emergency scenarios versus all possible emergency scenarios that might happen to the facility. Scenarios that already have appropriate mitigations are reviewed in order to adapt with the latest plan condition. Meanwhile, scenarios that were yet considered in the initial design are carefully assessed. New available technologies are identified and selected to mitigate this new identified scenario. Upon the completion of necessary modifications, facility emergency response procedures are updated comprehensively Triggered by full surface tank fire incident in one of refinery, detail gap analysis was performed to check the potential emergency scenario and its available mitigation at Senipah Terminal. Based on gap analysis, it was confirmed that initial design of this > 40 year storage tank Facility was not designed to cope with full surface fire but it was designed to mitigate rim seal fire. Based on thorough study, following are improvement of safety and operation aspect of storage tank which already been implemented including: provision of High Capacity Cannon Monitor (HCCM) complete with fire network and foam system improvement, on-line tank surveillance and monitoring system installation, rim gap minimizing and fire embark system improvement to improve existing rim seal firefighting system, spill containment system improvement, foam truck replacement to support firefighting scenario. Site emergency contingency plan was also updated to align with the latest modifications. Throughout plant lifetime, the emergency preparedness document is live document which should be continuously updated refering to the most recent standard and lesson learnt from the industry. Emergency preparedness is also much linked to the plant design. Any modification on the facility shall be followed by reviewing and updating existing plant emergency management system.

Major accident is one of the risks that oil and gas industries are exposed to. Although its probability of occurrence is low, the impact of this unfortunate event could result in significant losses in terms of personal safety, environment preservation, company asset, production and reputation. Therefore, risk management has to be in place, consisting of identification, assessment and prioritization of risks, followed by coordinated and economical application of resources to minimize, monitor and control the probability and/or impact of the unfortunate event. In anticipation of potential major accident, there was an initiative to develop a system to manage risks in operations. In order to do that, a Technological Risk Assessment (TRA) study has been done for the existing facilities. As a result, technological risks, which deal with events that may have catastrophic and disastrous consequences, could be identified. However, due to operational changes, the level of risks could differ from the one defined by the TRA study. These risks are what we call "technical integrity risks". In contrary to technological risks which are updated at every 5 years within the facility life cycle, technical integrity risks dynamically change over time in operational phase of the facility. Therefore, it was necessary to have one centralized database to register all the technical integrity risks. The database was named AGIR (Asset Global Integrity Risk) Register. Apart from its function as a database, AGIR was developed as a one-stop application for risk management processes. All cases identified as potential integrity threats are registered in the application. A risk assessment tool is also embedded in order to guide users to perform risk assessment based on company's risk matrix in more systematic and efficient way. A TRA database is also included as reference of risk level by design, providing also the major risk register of the facilities. For cases that are confirmed as integrity threats, follow-up of actions defined is also monitored in this application. Furthermore, the application also provides dashboard function to generate reports. This application provides transparency and traceability in the implementation of risk management system. Its features could still be enriched to cope with the company's future needs with regard to risk management.

Upstream process safety (UPS) events during drilling operations, including kicks and unexpected loss of fluids can occur due to a myriad of reasons viz., unexpected pressure variances, complex geology, or improperly executed procedures. Wellbore influx or kicks occur during drilling when formation pressure is greater than the density of the drilling fluid in the wellbore, resulting in the unexpected influx of fluids or gas into the wellbore due to the pressure variance. Similarly, if density of the drilling fluids exceed the formation pressure, wellbore fluids are unexpectedly forced into the formation or migrate into open fractures. Utilizing historical Health, Safety and Environment (HSE) incident tracking and drilling data for UPS events, specialized models can be constructed to identify the system causes for these occurrences. Too often investigations look at the symptom and relate it to the problem of an event, but do not perform an in-depth investigation to determine the root causes that actually contributed to the event. In some cases there could be a multitude of factors. Once the root cause is determined, a smart strategy can then be developed to mitigate the risks to a safe and cost effective level. By developing an understanding of the actual root causes and analyzing HSE and modeling data for a determined set of events, analysts discovered that approximately 94% of the UPS incidents associated with kicks and fluid loss were preventable using technologies and products readily available. A review of human performance also concluded that safety culture, lack of knowledge and the understanding that preventative planning can lessen UPS incidents and drive efficiency in operations, may not be shared throughout an organization. Challenges in alleviating UPS events lie with both subsurface complexity, as well as the value that an organization or decision makers place on disciplined and rigorous risk assessments, preventive planning and prescriptive operations to overcome subsurface challenges. The key to developing a smart mitigation strategy to alleviate risks, is through interactive collaboration between multi-discipline subject matter experts from different subsurface disciplines viz. geology, geomechanics, geophysics, as well as drilling fluids, well construction, wireline and drilling services analyzing each individual risk or hazard, leveraging the knowledge developed from the specialized models. Using this risk assessment, a customized approach to drilling risk management can be developed to address the relevant subsurface challenges. Some approaches may require several components to be implemented simultaneously in order to be effective. Proactive mitigation measures can be employed if a high-risk challenge is predicted during the integrated risk assessment approach, including proper preparation at the beginning of the project to reduce potential risks to people, environment, equipment and systems. By conducting a subsurface driven risk assessment and implementing barriers with different tools or services, UPS events can be attenuated or prevented. Additional benefits realized include reduced non-productive time (NPT) and increased efficiency for operations. A review of recent case histories in various regions including North Sea and the Middle East, demonstrate the benefits of a proactive approach to UPS.

For years, the oil and gas industry has been utilizing real-time sensors to monitor multiple parameters. In drilling operations, these sensors are highly important in achieving the well objectives. They provide data to guide the well execution and aid during the evaluation phase. The downside is the limited capability to identify operational anomalies. The latest popular strategy to mitigate this downside is using a Decision Support Center to obtain the most benefit from this data. Decision Support Center should be available for 24-hour operations and consists of multiple personnel to review data, provide path forward recommendation, and alert the field supervisor. During these past years, most companies have optimized the number personnel to keep competitive in a low oil price environment. However, some knowledge has been lost during the process. On the other hand, the industry worldwide is entering an era of digital transformation. This triggers the need for artificial intelligence systems that can translate analog knowledge from personnel to digital data, analyze for execution anomalies from sensor readings, and provide feedback and recommendations to the end-users. In one of largest mature onshore Indonesian blocks, a pilot implementation of artificial intelligence assisted Decision Support Center was developed. With limited time and cost, the project needed to be developed as fit-for-purpose. Thus, the system focused on the significant problem which historically caused million dollars in lost opportunity in the form of stuck pipe. A single stuck pipe event could result in a US$ 2.5 MM loss, which is more than 2 times the typical well AFE in this block. Beside surface and downhole sensors readings, subsurface prognosis, torque and drag model; operational best practices were also included in the system. Anomaly alarms were developed, including ECD limit by depth, pick up weight limit by depth, torque limit by depth, potential loss circulation zone, maximum allowable static time, and maximum allowable pumps off time. Whenever the sensor reading exceeds these limits, an automatic alarm would be generated and sent to the field supervisor, drilling superintendent and drilling engineer. As result, it only required 1 personnel per 4 rigs to maintain the process compare to 3-4 personnel per rig required with the conventional Decision Support Center process. This process successfully eliminated stuck pipe events though to the remaining of the drilling campaign of 56 wells, where the historical frequency had been 1 stuck pipe event out of 20 wells. Future improvement in this system will utilize machine learning to develop anomaly alarms by gathering data from offset well operations. An additional benefit of this system is to implement it in workover operations.

This paper is part of a research aims to develop a realistic valuation model of an unexplored oilfield using real options approach. We consider several sources of uncertainty, i.e. exploration outcome, reserve volume and production rate, oil prices, and interest rates. We make a realistic assumption for each uncertainty source. Exploration outcome follows a Bernoulli probability distribution, oil prices follows a two-factor mean-reverting process (the Schwartz-Smith model), and interest rates follows the Cox-Ingersoll-Ross model. Reserve volume and production rates are estimated using the compressible-liquid tank model with probabilistic reservoir and operational parameters. The complexity of the problem requires us to use Monte Carlo simulation to obtain the solution. An initial investigation using data from a particular reservoir found that 80% of the variance of the oilfield value was due to uncertain reservoir condition. We also found that if we could estimate those parameters accurately, the tank model has given close approximations on the reserve volume and production rates. The previous work on this issue suggested to generate parameter values from ‘similar’ reservoirs, where similarity was inferred based on lithology and depth. The probability dstribution of the parameters are assumed to be lognormal. We found this approach was rough and inaccurate. This motivated us to develop two different models to estimate those parameters. Our first model is an extension of the previous work using the Gaussian copula. In this model, instead of assuming lognormal probability distribution as in the previous work, we test the data against all possible distribution and choose the fittest one for each parameter. Association between parameters is modeled using the Gaussian copula. Our second model uses the exhaustive CHAID (Chi-square Automatic Interaction Detection) algorithm aims to estimate the net pay, porosity, initial oil saturation, initial oil formation volume factor, permeability, viscosity, initial pressure, and bottomhole pressure based on data assumed to be available prior to exploration, i.e. lithology, depth, deposition system and its confidence level, diagenetic overprint and its confidence level, structural compartmentalization and its confidence level, element of heterogeneity, and trap type. Other parameters like shape factor, skin factor, water compressibility, oil compressibility, and formation compressibility assumes some particular values. We use reservoir data from the Tertiary Oil Recovery Information System (TORIS) database to develop the models. We derive the CHAID model using data from 501 reservoirs which randomly divided into training set (70%) and test set (30%). We do not directly use the predicted values from the model. Instead, we use the algorithm to identify reservoirs that shared the same characteristic regarding a particular parameter, out of which the values of the parameters are generated during the simulation. We compared the results from both models and found that the CHAID-based model are more accurate. The novelty of this research comes from the use of machine learning to predict the values of parameters needed to estimate reserve volume and production rates in the valuation model of an unexplored oilfield. This contibutes in reducing uncertainty in the valuation of such risky assets.

The rapid expansion of the Australian gas industry has seen massive investment in mega-projects, but benefits from this have been impeded by the impact of severe project delays. Risks causing delays in upstream mega-projects are high, leading to frequent cost and schedule overruns. However, the absence of research concerning delays during this complex phase of mega-projects provides the opportunity to critically examine underlying challenges experienced by various project participants involved in upstream gas projects in Australia. Data was gathered through an extensive literature review, interviews with industry experts, and a survey. A list of risk factors extracted from the literature was checked with industry experts for relevance in upstream mega-projects, and missing risks were added. The survey was circulated to a random sample of people working within the natural gas projects domain, including clients, consultants, and contractor organisations. Using Likert-style five-point scales, participants rated the frequency of occurrence and severity of each of the risks impacting delays. A total of 70 risk factors were identified, which were then traced back to 10 risk sources that impact delays in upstream gas projects. The findings reveal that 72% of participants believe that the average delay in gas projects is between 10% and 30% in Australia. Moreover, 93% of participants mentioned that schedule slippage in the upstream phase causes severe challenges in attaining "first gas" and results in overall project delays. Based on the frequency of occurrence and severity indices, the magnitude of risk factors and sources was used to ascertain critical risks causing major delays. Kruskal-Wallis and Mann-Whitney U tests were applied to check the differences in perception of risk criticality influencing delays among the participants, who differed depending on work experience, job position, and the type of participants’ company. These tests indicated a good association in such perceptions. Key risk factors causing major delays included frequent change orders being issued by clients, unrealistic time schedules imposed on contracts, and poor organisational structures. Risks in mega-projects cannot be eliminated completely. However, a more precise identification and prioritisation of risks causing major delays, along with differences in risk perceptions of various project parties, will provide an informed and broader perspective to industry practitioners and stakeholders in managing risks more effectively to reduce upstream gas project delays.

Outcomes for oil and gas projects often fall short of the expectations predicted at project sanction. Appropriate use of Front End Loading (FEL) and Decision Analysis (DA) to achieve high Decision Quality (DQ) should increase the likelihood of achieving better outcomes. However, despite being successful methodologies, research has shown that they are not always applied. The focus of this paper is on how to encourage people to make better use of FEL and DA. Previous results from this research program have shown two key reasons why FEL and DA are not used more: an over-reliance on ‘experience’ and judgment for decision-making, rather than the use of structured processes; and projects being ‘schedule-driven’, i.e. meeting target dates being the primary objective. This paper focuses on insights from a survey conducted both to answer questions raised by this previous research and test the likely uptake of methods designed to encourage more effective use of FEL and DA/DQ. It shows that there is strong agreement that good FEL leads to better project outcomes, and that the FEL benchmark score is a good indicator of readiness for project sanction. However, perhaps competing with the desire to complete FEL, is the view (of around 2/3 of respondents) that it is important to drive the schedule in order to prevent ‘overworking’ – continued activity that adds little value. All respondents agreed that it is essential: that the decision maker clarifies the frame, scope and criteria for the decision; and to have regular discussions between the decision maker and the project team to bring alignment. However, responses indicated that these only occur in practice around half of the time. Similarly, formal assessments of DQ are made in less than half of key project decisions. Several novel solutions are proposed for increasing the likelihood of better project outcomes by improving the uptake and use of FEL and DA/DQ. These include: just-in-time training on FEL and DA/DQ; basing performance incentives on achieving high DQ and good FEL; and, developing a simple pragmatic assessment of FEL that can be used in-house. These suggestions were all supported by a majority of survey respondents.

It can take months, perhaps a year or two, to get through Front End Loading (FEL) stages with the current industry approaches. As the industry strives to be more efficient, faster to market in this lower for longer world, we need a different and much faster, lower risk approach that does not erode value. Multiple tools exist that allow subsurface/surface simulation integration and coupling, but these are cumbersome to configure and not appropriate for an early field development at the stage of pre-FEED (Front End Engineering and Design). To meet this challenge, an agile approach to Field Development Planning (FDP) has been established. The approach is inspired by agile project management techniques and best practices that are currently used in the automotive, aerospace, construction, software development industries and lean start-ups. It is based on parallel sprints rather than the waterfall approaches to project management. Collaborative teams work on parallel deliverables to create a minimum viable product (MVP) and value drivers for further development are established quantifiably with an Analytic Hierarchy Process (AHP). The notion of a fully representative dynamic techno-economic model is presented. This model applies a multi-dependent system thinking approach, with dynamic integration of economic, reservoir, subsea, facilities and schedule data. Two case studies are discussed where this approach was used to maximise economic benefits of the asset and accelerate the decision-making process during FEL stages: Identification of the best compression solution to optimise the economic outcome of production from a complex group of 350 wells intersecting different reservoirs. The result of this example was an 18-month acceleration of the decision process and 30% cost saving. Deciding whether the FEED should be oriented towards simultaneous or sequential production for the development of two marginal offshore satellite fields. This presentation will be of interest to anyone looking to speed up the time to first oil/gas and reduce production costs on undeveloped or underdeveloped fields and bid more confidently on assets during licence rounds with less risk. It will also be of interest to those wanting to accelerate their decision-making process during FEL stages from months or years to weeks and allow decision makers to visualise and test inter-dependencies creatively with less cognitive bias.

A novel extended bowtie risk assessment methodology was used to develop the safety assessments for three Major Hazard Facilities (MHFs). Combined with an innovative risk management tool for operationalizing risk management processes, it provides a clear overview of each facility's current operational risk profile and the health of the safety critical barriers. This paper describes the bowtie methodology, its application in the development of the MHF safety assessments and the operationalization of the safety assessments through the risk management tool.

RFCC is one of the most important processes of petrochemical industry and is also a frequent accident process due to the inflammable and explosive material and intermediate product. Optimized risk management in RFCC plays a great role in guaranteeing exploration and production work safely and smoothly. On this premise, the Risk-Based inspection (RBI) was presented and widely prevailed in petrochemical enterprises. Optimized RBI on RFCC starts at collection of inspection data followed by identification and assessment of damage mechanism and failure modes. Equipment risk is calculated with the help of Orbit-onshore (DNV) software. According to quantitative results, item's risk level are assigned and prioritized by risk matrix so that critical one which would be inspected thoroughly is noticed. Eventually, an appropriate inspection program for RFCC is designed with numbers of proper measures to extend interval by assigning resources of inspection and maintenance.

Globalization inevitably drives prices of commodities and services lower. As such, to remain competitive in the Oil & Gas industry it is imperative in low oil prices regimes to decrease operating costs. A key element of low operating costs in hydrocarbon exploration, production and refining, is corrosion control. In this paper the development of corrosion circuits/loops is improved by categorizing sixty four damage mechanisms based on operating preconditions, material susceptibility and monitoring methods. The inspection resource requirements are determined for each Refinery unit based on number of damage mechanisms, the required monitoring methods and the screening of regulated equipment. Corrosion loops are developed based on failure mechanism applicability and not arbitrarily changes in operating conditions or the probability of failure. Material selection methods for critical units during detailed design should not be qualitative to avoid over/under designs that are carried over to operating/inspection programs. When inspection effectiveness does not add significant value to risk reduction due to a gap between operating requirements and turnaround intervals, consequence mitigation, including operating practices should be examined. Therefore, risk studies including RCM, HAZOP and QRA should be aligned with RBI and validated by failure and consequence statistics. IOW assignment should consider design risk profile and operating (operations and inspection) risk profiles. By far this is the underlining reasons why operators are unable to leverage management systems to mitigate risk, lower operating cost and avoid major accidents. The importance of managing risk transfer between equipment design, operation, inspection, safety and system integration is highlighted. Integrity operating windows are not exclusive. The alignment of all the installation risks enables the operator to leverage risk profiles in manner that satisfies the statutory body and addresses its business needs.

While many companies utilize advanced systems for quantifying and normalizing geologic risks, and some have standardized above ground risk characterization, relatively few use this information effectively when assessing risks at a corporate portfolio or aggregate level. Detailed project assessments are often distilled into expected value representations when combined at a corporate level, leaving the company exposed to potential risk concentrations and aggregate performance variability. This paper demonstrates an approach to assessing value and risks at a portfolio level when the underlying components contain opportunity specific and potentially unique risk drivers. Identifying critical risks at the corporate portfolio level and translating this information into efficient data compilation requests and allocation decisions requires a structured and disciplined approach. While the techniques in describing geological and above ground risks at a project level are commonly applied and portfolio aggregations of projects are routinely conducted, the tripping point for many organizations is in effectively leveraging the detailed stochastic information at a portfolio level. Gaining insights at the aggregate level and maintaining the appropriate perspective on these uncertainties can yield significant value to organizations as they mitigate risks and adjust plans to exploit opportunities. Many of the techniques used to quantify ‘portfolio risk’, such as efficient frontier risk measures, multi-objective scoring, or combined approaches fail in terms of providing decision makers with tangible and practical guidance as to the real impact of specific decisions on objectives. This paper codifies an approach that makes it possible to align the degree of acceptable corporate level uncertainties (risk) with the underlying, project level descriptions. This basic methodology may be employed and expanded to a wide range of asset types and diverse portfolio sets, independent of company size or complexity. A portfolio model was constructed, with individual projects described with varying degrees of uncertainty detail. This provides a clear example of the methodology while demonstrating the relative importance of project specific uncertainties as these are translated into an aggregate corporate view. The simple analytic structure described in this paper may be scaled to represent much more complex uncertainty environments and more diverse assets as required. The value in properly capturing project specific uncertainties and maintaining these descriptions when assessing portfolio value and risks is quantified for the examples depicted.

Because of the complex geological structure and unpredictable geologic environment, drilling engineering is characterized by high risk and high cost, especially the drilling processes of complex formation or deep water condition. Controlling drilling cost and ensuring the drilling safe has been the focus of research at home and abroad. So this article's objective is to establish the casing program optimization method based on risk and cost coordination. In this article, based on the drilling quantitative risk assessment and the drilling accidents report, the risk probability profile can be obtained. Then according to the theory of fuzzy mathematics, the model of risk degree judgment was established. The drilling risk probability profile is divided into three parts: the safe region, the transitional region and the dangerous region. No special treatment is necessary for the safe region. Risk in the dangerous region must be avoided before drilling. The risk in the transitional region must take account of both risks and costs. The risk treatment and aversion cost calculation model were established. Then the coordination of drilling risk and cost was proposed. Finally, the optimized casing program based on this method was obtained. After the summarization of this principle, taking the drilling data of one block of a basin in west China as the example, the risk level identification results were mainly identical with the realities, and indicated that the method could satisfy the needs of drilling engineering. Case study showed that the decision making for casing design of one pre-drill well was optimized based on the coordination mechanism. The well was successfully completed without risks and the drilling cost decreased by 15%.

Acoustic Induced Vibration (AIV) refers to the high acoustic energy generated by pressure-reducing devices that excite pipe shell vibration modes, producing excessive dynamic stress. Analysis of this risk is an important part of Asset Integrity Management systems as AIV can cause catastrophic piping failure. Existing guidelines address this risk through an analytical assessment. However, these methodologies are not fully known and input parameters are limited. Some limits to the guidelines are pointed out with recommendations to improve them. The approach presented for identifying AIV damage is based on a dynamic stress evaluation at pipe discontinuities (welded connections and supports). This evaluation is performed through a fluid-structure coupling Finite Element Analysis. Pressure fluctuations inside the pipe are predicted and coupled with a pipe structural analysis. This methodology is provided with its validation through measurement on an actual AIV field case, corresponding to a crack initiation due to AIV on a FPSO flare network tail pipe. To conclude the paper, the method is then applied to quantitatively assess the mitigation actions' efficiency base on an actual case. Different solutions have been tested individually to end up with a final solution that reduces the damage to acceptable levels in the most cost-effective manner. The sources of this high acoustic energy are pressure-reducing devices (valves, restricted orifices…) with high pressure drop and important mass flow rate. In such devices, the amount of energy dissipated is quite high, although most of the energy is converted to heat but there is still a significant part converted to sound or pressure waves that will excite the pipe wall. This broadband and high-frequency excitation propagates through the pipe, amplified by transverse acoustic pipe modes which later excite the pipe's shell vibration mode. While running along straight pipes, the impact of vibration is limited due to axisymmetry of the pipe shell mode shape. However, when the excitation comes to a non-axisymmetrical discontinuity (branch, small bore, support…), vibrations are amplified, leading to high dynamic stress that can cause pipe fatigue failure. As these vibrations occur at high frequencies, i.e. with a high fatigue cycle rate, fatigue failure occurs within a few minutes to a few hours. Figure 1 (a) Fluid Acoustic mode; (b) Pipe shell mode. For offshore plant, the major risk associated with this phenomenon is related to flare systems. Blowdown valves, restricted orifices and pressure safety valves in these systems usually encounter large pressure drops and important mass flow rates. As the acoustic energy generated by these devices propagates downstream with small attenuation, the whole flare network is affected by the risk of AIV failure. Flare systems are gas associated systems and they are safety-related, potential pipe failure could lead to catastrophic consequences. Therefore, assessing and controlling the AIV risk is an essential part of Asset Integrity Management. AIV has been an on-going research subject since initial publications in the late 70s and methodologies have been developed to help engineers to assess this risk. The dominant methodology for the Oil & Gas industry is published by the Energy Institute. In Energy Institute guidelines address the AIV risk through an analytical assessment methodology. It is very efficient in performing a quick screening for large numbers of pipes. However, when it comes to mitigation measures, the limited number of input parameters used to quantify the Likelihood of Failure (LOF) reduces the range of possible mitigation measures. Since the efficiency of certain mitigation measures are not LOF calculation parameters and therefore cannot be assessed. To overcome this limitation, a new detailed Finite Element methodology has been developed using the coupling between fluid and structure, making it possible to predict dynamic stress for complex piping models. This methodology will be introduced in the next chapter, including a validation through measurements on actual AIV field case. Using this methodology, different AIV mitigation actions (such as: the use of sweepolets, forged tees, full encirclement supports, full encirclement wrap branch reinforcements) that not included in the scopes of Energy Institute guidelines are assessed. Comparison between computation results with and without mitigation measures makes it possible to quantify the impact of such modifications accurately and to establish a LOF adjustment coefficient when using these modifications.

Robust co-activities management is one key to combine continuous production and development in upstream operation. In the context of Mahakam Block, green and brown field developments are continuously adding portfolio, simultaneously with routine production activities. Huge volume of simultaneous operation in Mahakam could be seen in 2013 operation, with more than 20 million manhours, 6 Jack up Rigs, 5 Swamp Barge Rigs, 36 Well Intervention barges, 22 Construction Barges were managed. This paper will describe specifity of simultaneous operation in Mahakam Block, and presenting improvement efforts to maintain operation excellence of simultaneous activities in offshore and swamp in the past 3 years. Simultaneous operations in Mahakam are applicable in the field of production with drilling, well intervention, and construction / project. The improvement efforts went through mapping, gap analysis, workshop, and validation. Organization improvement efforts were including standard guideline to determine work criticality using quantitative approach, introduction of routine coactivity matrix and recurrent activities sheets. The guideline has successfully helping harmonization among operation sites and all stakeholders. Reinforcement of audit is another aspect contributing to overall excellence of TEPI safety and production performance in 2016.

Kuwait Oil Company (KOC) is developing Jurassic fields spread over 65 X 50 Km in North Kuwait, which are aimed to support the state's growing gas demands. The present contribution to Jurassic production is from Raudhatain, Sabriyah, NWRA, Um-Nigah & Dhabi fields of sour MM/NS reservoirs. Some of the wells and flowlines of these fields are located outside current KOC security fence very close to the existing public Farm Houses, posing great threat to public in the event of toxic H2S gas release. This paper mainly describes KOC's Production & Project Gas Group initiatives undertaken to mitigate the threat to public safety (potential Societal Risk) by implementing effective barriers to minimize the source and impact of any toxic gas release. Immediate safety measures undertaken include installation of field crash barriers along entire flowlines/corridors that prevent damage to existing surface flowlines. Mid-term protection by boundary fencing is in advance stage of installation for UN, NWRA, DA & Liyah fields and H2S warning signs are installed at well heads as well as along flowline routes. Long-term plans are underway to install required safety instrumented instrumentation for improved safeguarding systems of well heads, flow lines & the Early Production Facility (EPF-50) protection. The plan includes monitoring facilities of potential H2S release and public warning system (in two phases) for emergency preparedness and crisis management. The paper presents few specific cases of how by implementing the safety measures and barrier installations so far have yielded results in avoidance of hazardous condition and unsafe incident. In addition, the paper also presents process safety features like hazard analysis and risk assessment studies (HAZOP, SIL assessment, QRA etc.) carried out to identify potential risks associated with site specific situations (both for Jurassic field areas and EPF-50 plant) based on ALARP principle.

The use of a probabilistic estimation analysis system that applies Monte Carlo simulation techniques to generate a deeper understanding of the risks inherent in well operations. The software and the process associated with its application represent a step forward in providing operators with a tool for identifying, quantifying and managing risk. A process flow map is generated that shows all the risks that have been addressed along the probabilities and options. This ensures that the team understands what they are addressing and all contingency materials services etc. are addressed. With a flexible process new information leads to a need for the steps to be easily added or adjusted. By producing reports to an industry standard spreadsheet that show all inputs and output information, there is no confusion as to what assumptions have been made, and they are all captured. Whilst probabilistic estimation techniques are used routinely to characterise risks associated with geological and reservoir uncertainty, these techniques have not been routinely applied to well activities. For many decision-makers, the traditional deterministic cost estimate has produced satisfactory results. However, in an increasingly competitive business environment, project decisions need to be made in a more informed manner for organisations to become "Best in Class". The application of a risk-weighted probabilistic cost and schedule estimation tool that can provide a comprehensive understanding of the time-cost risk spread in well abandonment projects represents a significant progression and can help provide detailed answers to the three basic questions in managing project costs: What is the likelihood of overrunning the project budget? What is the level of exposure associated with any overrun that may occur? Where do the individual risks lie that need to be mitigated against in order to avoid overrun? If the risks can be mitigated, then the level of exposure can be reduced and projects can be delivered with greater budgetary certainty, conversely if the risk cannot be mitigated, how can it affect the total budget, and is it wise to carry through the operation?

TOTAL E&P Indonésie (TEPI) is the biggest gas producer in Indonesia, who also produces oil. At the time this paper is written, TEPI is operating six Production Sites, two Logistic Bases, seven Drilling Rigs, hundreds of Floating Vessels and thousands of Oil & Gas wells. Central Processing Area (CPA) is a site that produces oil with some free gas from 555 deltaic multilayer sand reservoirs of Handil field. The site was built 40 years ago with its peak production around 200,000 BPD of oil in 1977. Today CPA produces on average 16,000 B/D of oil and 30 MMsfcd of gas. From total 694 well strings, only about 20% of it is actively flowing; these well strings are spread over 65 clusters. Most of the oil wells are artificially lifted by pump or gas lift compressors. Facilities were added and adapted along with the needs, such as High and Low Pressure gas compressors and Gas Lift Compression unit. Several Enhanced Oil Recovery (EOR) projects had been tried, such as gas injection, air injection, and water injection. Currently the only artificial lift remaining is gas lift, and the EOR remain is water injection; the rests are stopped and modified. Nowadays, the main challenges of this mature field are integrity and HSE. Old design, obsolescence, modification of existing facility, and integrating with new technology generates several risks. Along with the maturity, leaks and potential leaks increase over time. The issues are corrosion, surface cracks, seepages, fugitive emission, obsolete equipment, increasing sand production, etc. Furthermore, several disused equipment also become another threat. This paper will discuss how CPA, a 40 years old Oil & Gas Production Installation, manages its Integrity and HSE. It will explain the challenges, good initiatives, and room for improvements. The topics will include Risk assessment & Identification, Inspection strategy, Integrity, Maintenance, Preservations, Work Permit implementation, Emergency exercise, etc.