The objective of this paper is to share the holistic approach to managing aging fleet for offshore fixed steel structures. PETRONAS is currently operating a fleet of more than 200 fixed offshore structures in Malaysian water. More than half of it has exceeded the original design life. With enhanced oil recovery and other developing technologies, offshore platforms often than not are required to continue operating beyond its original design life. A holistic approach for life extension of fixed offshore structures are being developed to ensure safe operations of the facilities. PETRONAS has started SIM journey since 2007. The approach of Data, Evaluation, Strategy and Programme in line with API RP 2SIM set the basis for managing the integrity of the offshore fleet. An integrated solution was developed to manage both topsides and substructures. The Structural Integrity Compliance System (SICS) which houses the integrity management of topsides deteriorations to prioritize resources through risk based anomalies management. Risk based underwater inspection also formed part of the solutions, addressing mainly extreme storm in the region. Other Major Accidental Hazards (MAHs) risk ranking included in SICS are vessel collision and seismic. Management of facilities with minimal redundancy such as guyed wire monopod is addressed through time based inspection. A regional hazard curve is also developed to ensure the facilities are meeting the acceptance criteria set forth by the industry. Besides aging, other integrity triggers including shallow gas and subsidence required a different scheme in managing the integrity of the facilities, primarily addressed through a comprehensive monitoring programme. There is no one size fit all recipe in managing the aged platforms for life extension. The data plays a crucial role in ensuring the right methodology is deployed in support of digitalization and data driven decision making. Implementation of the system is proven to be reliable in ensuring the offshore fixed structures are intact to support safe and continuous operations to the operator in a cost optimum manner. The data analytics help to enhance the predictive model to optimize the inspection and maintenance programme. Strong ownership and commitment of the structural integrity engineers in ensuring the data integrity maintain the challenge in sustainability of the system and provide reliable source for data driven decision making to the operator. Category: Operational Excellence (136 - Managing Aging Facilities)

Production forecasts provide fundamental input to upstream business decisions, for example in resource volume reporting, field development and production planning. Very often in mature fields, having sufficient cumulative production, field forecasts are performed based on aggregating type curves for new wells and decline curve analysis for existing wells. Conventionally, they are derived by manual trend fitting which is subjective and any iteration incorporating new data is time consuming. The advanced analytics approach presented in this paper can provide rapid and credible forecasts along with more robust quantification of uncertainties as compared to the conventional manual approach. The first step involved in the forecast automation using advanced analytics is data integration in which the production, geological, and surveillance data are combined. Then integrated dashboards are created to infer trends in production behavior. Based on these trends at the most granular forecast level, petroleum engineering based algorithms are developed to automatically select the decline period. Thereafter, multiple scenarios of historical data are generated based on historical allocation and measurement uncertainty. Through each set of these historical scenarios, best fits curves following Arp's equation are extrapolated into the future to generate multiple forecast scenarios. Finally, field level forecast is generated by probabilistically aggregating individual granular level forecasts. The automated forecast program developed is computationally very fast as 500 forecast scenarios at the well level can be generated in 30 seconds, while the full field forecast with 50 wells takes about 30 minutes to generate. Automation of decline period selection and curve fitting eliminates the subjectivity by standardizing the process and reduces the chances of manual errors. Abandonment criteria, discounting and uptime variations can easily be accommodated in the automated process. Visualizations are utilized at each step for quality check and analysis. Forecasts from alternate methodologies are used to validate the forecast ranges coming out from this method. Uncertainties quantification in this approach is found to be more quantifiable and consistent compared to the conventional deterministic approach. Production dashboards created in this workflow by integrating production, surveillance, geological data and forecasts are a very effective tool to perform field reviews and communicate outcomes. The approach described above for decline curve analysis can easily be extended to any type-curve based forecasting. Automation of performance-based decline curve and type curve forecast methodologies has the potential to reduce huge manhours involved in their periodic updates by an order of magnitude that can be utilized to carry out other critical analysis. It is very useful in mature assets with large well inventory, huge dataset and where continuously new data are being added. Standardization of workflow, implementation ease and accuracy will tempt practitioners to use it and thereby develop skills in data analytics.

Manual Material Handling (MMH) activities (i.e. lifting, lowering, pushing, pulling, and carrying) pose the risk of injury to the musculoskeletal system of the workers. The injuries may lead to decreased work performance, and increased errors, absenteeism and health care cost. Therefore, it is necessary to know whether the workers of one of the Oil and Gas Company in Thailand are facing with the injury problem and to find the solutions for preventing those injuries. The procedure of the solution is walk-through survey of hazards and risks of Work-Related Musculoskeletal Disorders (WMSDs) among the workers (both onshore and offshore platforms) whose works involved in MMH tasks and providing the recommendation and followed up by Medical and Occupational Health team of the Company together with the physical therapists from one of the famous academic institute in Thailand who are collectively called "the research team". The research team conducted a walk-through survey and performed preliminary physical examination at an onshore and all offshore platforms. The survey included characteristics of each work, intensity and frequency of workload, work environment and potential risk factors. Physical fitness assessment including muscle power and weakness was also determined. The findings from the walk-through surveys, work procedure were analyzed to identify risk factors of work-related musculoskeletal injuries. The findings from preliminary physical examination in approximately 300 operating workers, upper cross and lower cross syndromes were found, indicating muscle imbalance in MMH workers. Task activities were analyzed on each procedure which has risk factors including awkward posture, repetitive movement, manual handling, forceful exertion, work environment, equipment, and cognitive and psychosocial issues. The research team reported risk factors with consequences and provided recommendation for each factor regarding engineering, administrative, and individual controls. For example, offshore platform has many floors which are designed for particular function (office, bedroom, dining room, etc.). Offshore workers regularly perform high repetitive stepping up and down stairs making them prone to hip and leg muscles imbalance. There is high compression at knee joint which may lead to early degenerative joint or knee pain. The recommendation is to provide properly work break and training with principle of ergonomics in workplaces including ergonomic risk factors; risk prevention; and strengthening exercise. Findings on this study lead to the specific designed exercise program and training to counteract the effect of heavy musculoskeletal activities related to MMH in daily work. The study will also serve as a guide for developing of MMH guideline for the company.

Currently, decisions involving a huge amount of money and resources are based on the outcome of simulations. Consequently, an increase in the computational resources has attracted engineers and scientists to increase the complexity of the mathematical models and their numerical algorithms to design or analyze various systems. On the other hand, the transparency of these models has decreased and the sensitivity of the outcome of these simulations on, for instant, certain assumptions or input parameters is often not known a priori. Furthermore, validation of the models for complex systems in which full scale measurements are limited or even impossible, gives more challenges to the decisions made based on these numerical simulations. Additionally, robust design to consider off-design conditions in a systematic manner is of great importance in oil and gas industry. Therefore, it would be essential to develop a systematic procedure to quantify the sensitivities and errors associated with each set of simulations in an objective manner. Uncertainty quantification (UQ) could be used as a tool to provide the validity of a performed simulation. This study describes the current research and opportunities for parametric analysis and uncertainty quantification in the flow assurance such as in performance prediction and validation, risk assessment, decision making and robust design. Additionally, we describe the importance and benefits of probabilistic analysis instead of deterministic analysis. Uncertainty quantification increases the computational expenses and effort of performing deterministic simulations. Therefore, an efficient method to quantify the uncertainties such as probabilistic collocation or surrogate models are required to reduce the computational costs without losing the accuracy of the analysis. Parametric analysis and uncertainty quantification will give more insights in the validity of simulation data than traditional methods. For instance, using the newly proposed methods will expose the sensitivity of the simulation results to off-design conditions and consequently leads to a systematic decision making based on the probability of an event occurrence. These methods could be used to quantify the most sensitive parameters in the system and the effect of their propagation to the outcome of the model. It is shown that performing non-deterministic analysis in some cases is a necessity.

This paper is about Wellhead and X-Mas Tree Seal Integrity issues and the innovative approach adopted by Qatargas (QG) to deal with them. It provides a brief about measures taken to minimize the risk for operating wells with Wellhead and X-Mas Tree Seal integrity issues. QG started production in 1996 and is now one the premier LNG company in the world. After six years of its initial start-up, results of Wellhead and X-Mas Tree Seal tests indicated possible Wellhead and X-Mas Tree seal integrity issues. At that time this matter was thought to be manageable. In 2011, a Peer Review was arranged between QG, its Shareholders, and the Original Equipment Manufacturer (OEM) to analyze the current risk profile of the wells and decide on an action plan. Retesting of wellhead seals was carried out at the end of 2012. Instead of using the conventional approach, new techniques were applied to test the seals. The applied seal testing method was significantly different than the conventional test method, which eliminates the probability of damaging seals while testing. This paper will also highlight the difference in the testing approach. Detailed analysis of test result indicated that the seal integrity issues aggravated over time. Peer Reviews and root cause failure analysis (RCFA) were conducted to understand the cause of many failures. A wellhead design change was proposed to rectify the seal integrity issue and to eliminate the identified root cause; this paper contains details of internal design changes. The paper also covers the details of Finite Element Analysis (FEA) and RCFA. It also covers details of all possible solutions that were thought to be effective initially, but later on were recognized as short term solutions.

There is an ever increasing need to extend the life of aging offshore structures beyond their original design life. Whether these structures are fixed offshore rigs or floating facilities, operators are continually looking for requalification and extension of the service life aimed at ensuring the integrity of the structure. With a continued requirement to produce oil or gas, either from the original fields or as a base for neighbouring subsea completions, many of these respective offshore installations are likely to remain operational for a period of time in the foreseeable future. The ageing offshore infrastructure presents a constant and growing challenge. Ageing is characterised by deterioration, change in operational conditions or accidental damages which, in the severe operational environment offshore, can be significant with serious consequences for installation integrity if not managed adequately and efficiently. In order to ensure technical and operational integrity of these ageing facilities, the fitness for service of these structures should be maintained. Maximising the availability and productivity of the field, whilst operating safely and with minimal impact on the environment, is a major concern for requalification and life extension. Structural integrity management (SIM) and inspection campaigns are important inputs in the Asset Integrity Management and the maintenance of structural integrity is a significant consideration in the safety management and life extension of offshore installations. Detailed integrity assessments are needed to demonstrate that there is sufficient technical, operational and organisational integrity to continue safe operation throughout an extended service life. Information on history, characteristic data, condition data and inspection results are required to assess the current state and to predict the future state of the facility and the possible extension of service life. However unique environmental conditions, type of structures, fabrications and installation methodologies used in Middle East required attention in particular, development of hazard curves and risk mitigation of the potential regional degradation mechanisms. During the life-cycle of an offshore structure the ultimate capacity is also an important attribute that affects the life expectancy, requalification and life extension of the facility, and can significantly influence the reliability levels and operational costs. This paper presents state of art practices in life extension of existing offshore structures and an overview of a regional hazard curves evaluation methodology and proposed regional correction factors represented risk to the integrity of a facility and the required procedures and re assessment criteria for deciding on life extension in particular the one with the importance for Middle East region. This paper also provides an overall view in the structural requirements, justifications and calibrations of the original design for the life extension to maintain the safety level by means of a maintenance and inspection programs balancing the ageing mechanisms and improving the reliability of assessment results

Uncertainty quantification on reserves estimation is a fundamental task for project validation on offshore green fields and also for the selection of a development plan that is robust to those uncertainties. To test the robustness of several development plans is then fundamental to be able to evaluate the impact of this uncertainty with low computational cost. Structural, geological and dynamic uncertainties are integrated in a new workflow based on a set of embedded response surfaces. The first step consists in building an experimental design with only structural and geological parameters to evaluate the impact of such uncertainties on static responses such as oil initially in place. In the second step, this experimental design is completed with additional dynamic parameters. The novelty of the static and dynamic design merging is to incorporate the previously obtained static response surface in addition to the uncertain parameters. By embedding the static response in the variables we obtain a response surface on the reserves more regular and more predictive. In this workflow, mainly applied to green fields, the impact of local geological uncertainty is usually of second order respect to other global uncertainties and it is taken into account as random noise whose variance may depend on the static response. The method is applied to a real green field with complex multi-level heterogeneities and it is compared to more standard approaches such as Monte Carlo. We manage to obtain a very good response surface quality for the static response (oil in place) that is then embedded in the reserves response surface. The final accuracy of this response surface is sensibly increased respect to a classical approach considering only static and/or dynamic parameters at minor costs in terms of reservoir simulations. The new approach reduces sensibly the number of reservoir simulations needed for an accurate uncertainty and risk assessment when applied to select the more robust development plan selected from a set of possible candidates. It also provides useful sensitivity analysis measures to guide possible data acquisition campaign in order to reduce risks and take better decisions.

Abstract Gross rock volume is typically the biggest uncertainty in volumetric estimation, especially early in field life. Assumptions about fluid contacts are often the biggest component of volumetric uncertainty. This paper will examine how a better understanding of hydrocarbon trap and seal capacity allows more accurate volumetric estimates and improved risk assessment. Recent advances in several areas such as basin modelling, hydrocarbon charge, seal capacity and fault seal analysis have allowed a more comprehensive understanding of hydrocarbon traps. Hydrocarbon charge studies indicate that the proportions of generated hydrocarbons that are trapped in conventional reservoirs, the trapping efficiency, are very low, in the order of a few percent. Many times more hydrocarbons are generated than traps have the capacity to store. Analysis of individual fields suggests that many traps are filled to capacity rather than to structural spill points. Fill capacity may be limited due to lack of top seal or fault seal. Fields that are not filled to structural spill are often limited by trap capacity rather than by insufficient charge. Hydrocarbon phase in a trap is affected not only by source rock type and maturity, but also by seal capacity. With exploration wells often targeted at or near the crest of structural highs, over-optimistic assumptions about fluid contacts, in particular an assumption of fill-to-spill is a major cause of misunderstanding volumetric uncertainty. These observations and results have implications throughout the life cycle of a field, from risk assessment of prospects to estimation of volume ranges during exploration, appraisal and development. Look-backs and post-mortems are also useful to assess whether previous assumptions about hydrocarbon charge, seal capacity and fill mechanisms have been accurate or if they need revision. Analogues and lessons learned from existing fields and discoveries can also provide valuable insight into future predictions. Assessing volumetric uncertainty in terms of trap and seal capacity rather than relative to structural spill points allows better quantification of volumetric uncertainty. Hydrocarbon Generation and Trapping Efficiency Previous studies of hydrocarbon trapping efficiency have suggested that a relatively small proportion of generated hydrocarbons are conventionally trapped. Large proportions of the hydrocarbons generated are retained in the source rock without migrating, and remain as targets for unconventional reservoir development. Of the hydrocarbons that are expelled from source rocks, most are lost to the surface or are retained in carrier beds. The proportion of hydrocarbons captured in conventional traps is estimated to range from a few percent to around ten percent. Figure 1 highlights the large proportion of hydrocarbons retained in the source rock, but also shows the relatively small amount of conventionally trapped hydrocarbons. Expelled hydrocarbon volumes are typically many times greater than trapped hydrocarbon volumes.

Abstract Acquisition and interpretation methods to optimize horizontal wells have been broadly introduced in the industry nowadays. It has evolved from the basic and conventional technology such as gamma ray and average resistivity to the latest deep directional boundary detection method. Technically, all methods can be used to place a horizontal well. But the amount of information available for interpretation and real-time decision making such as measurement sensitivity, vertical resolution, and depth of investigation are different and unique for each technology, which could lead to different results in the placement of the well and thus the production profile. Horizontal well targets also vary from thin beds, thin oil rim in a single sand or across multiple sands with high angle cross section, laterally heterolithic reservoir, to massive thick reservoir; each of which have their own characteristics that can be interpreted from the log measurements. However, high angle effects such as anisotropy, shoulder beds or bed boundary will affect the measurements which may then affect the well placement interpretation accuracy and execution efficiency if not anticipated or understood well. Therefore, a proper risk assessment and technology selection in the early planning stage is critical, as most operators will need to allocate the budget to deploy the selected technology and methods. This paper presents a horizontal well risk assessment workflow from geosteering and formation evaluation perspectives based on the well placement experiences and geological environments in South East Asia. The workflow provides guidelines and general references for horizontal well technical analysis during the early planning stage which will help to optimally manage the risk associated with horizontal well projects. It involves risk assessment based on the geological condition and well objectives, followed by feasibility modeling phase to compare different methods and technologies, and finally the technology selection process to achieve the well objectives. Introduction Despite horizontal drilling costing almost double compared to vertical well expenditure, the concept has become popularly adopted in the oil and gas industry, beneficially increasing the production rate in mature or brown field. The planning and execution of a horizontal well has many challenges mainly related to directional control, geological uncertainty and reservoir characterization. Horizontal wells approach the target formation nearly parallel to the bedding plane; hence, it is also correlated to a small TVD windows target. The inability of seismic to interprete micro fault and reservoir variations along the target well will significantly reduce the net to gross ratio inside the pay zone. Many of horizontal well's failures are resulted from these two issues hence requires the operator to plan both the well path and geological target more accurately. Well Placement, which includes a planned interactive geosteering along the wellbore using geological data, combines technology and process with collaboration of multi domain disciplines. The well placement method is well known for years as a proven concept that has led to the success of horizontal drilling. Year to date, there are 5 known types of well placement method which is commonly used in South East Asia region; Geometrical drilling. The aim of this method is to drill conventionally with directional assembly to reach the reservoir target. Geometrical drilling is employable if the reservoir target is more than 100 ft thick and has many offset wells drilled around the target zone. The risk of using this type of horizontal well remains big as the survey EOU (Ellipsoidal of Uncertainty) could be an issue if drilling a long well. Therefore, proper advanced survey calculation method has to be applied in order to reduce survey uncertainty.

Abstract In 2010, a risk analysis taking into account both uncertainties in reservoir parameters and at the same time accounting for real time pore pressure measurements during a drilling operation on the Norwegian continental shelf (NCS), was completed. The plan was to drill through seven reservoirs, each independent of each other with a vast amount of uncertainties in the pore and fracturing pressure due to years of injection and production. The risk analysis was first made as an input to the drill plan, using best reservoir parameters available as well as expert judgments. Simulations were performed within a Monte Carlo (MC) framework. Results like for instance probabilities for fracturing and kick for drilling through the next reservoir(s) or tripping out, as well as an optimum mud weight for reducing risk, were obtained. The analysis was updated real time as the pore pressures were logged during the drilling phase, providing the best possible risk picture and giving the decision takers a possibility to update the drill plan before drilling through the next reservoirs. This paper describes how the main characteristics of the reservoirs were modeled and how the risk analyses were performed. Simulations obtained, both before and during the drilling operations, are presented. Results like the probabilities of fracturing and kicks as a function of reservoir parameters and number of reservoirs drilled, as well as optimum mud weight for risk reduction, are emphasized. Introduction Risk analyses are widely used by operators on the Norwegian continental shelf (NCS) to manage risk during drilling and completion phases. The analyses should reflect potential hazards and unwanted events during the operations, and are mainly based on pre-assumptions and best available information. Uncertainties of well specific parameters are usually dealt with in a conservative manner. However, risk analyses taking into account real time pore pressure measurements have, to the author's knowledge, not previously been performed. Considerable geologic uncertainty introducing potential narrow pressure margins were key issues in the planning of drilling a sidestep in a mature oil and gas field on the NCS. The field has been produced for some time, and several reservoirs had been subject to injection. Forthcoming decisions related to selection of mud properties and operational procedures were a challenge, and the overall risk level of the drilling operation was unclear. It was originally decided to undertake a quantitative risk analysis (QRA) to improve the overall risk picture and to form a stronger basis for decision-making in the development of the drilling program. Later in the project, one clearly saw the advantage of having the risk picture re-evaluated as the pore pressures were measured. The objective of this paper is to present the stages of the QRAs in the well planning process, the results and their applicability as decision support for the project. The QRAs was performed by use of the KickRisk analysis tool. This tool is based on a pressure control model, where factors influencing the bottom hole pressure (BHP) throughout the various phases of the construction of a well section are decomposed. The model includes down hole, fluid, equipment and operator-related aspects and their impact on hydrostatic, friction and surge/swab pressure effects. The analysis implies gathering of input on the uncertainty of these quantities in terms of probabilities and probability distributions. By Monte Carlo simulation, the resulting probabilities of entering a state of underbalance with the pore pressure (kick) and of exceeding of the fracturing pressure (fracturing) are derived, and the factors that are main contributors to the risk are identified.

Abstract This paper presents various techniques/ tools used to demonstrate the major Health, Safety and Environment (HSE) risks involved in the tight gas appraisal program, especially in designing the surface facility for the Trial Production Operation (TPO), has been reduced to As Low As Reasonably Practicable (ALARP). In the challenging environment of central Sichuan basin i.e. local hilly terrain and densely populated farm land, the paper looks at the local requirement and importance of the analysis right from the design phase for a safe and efficient operation of the TPO facility. The techniques covered include Hazard Identification (HAZID) Study, Hazard and Operability Study (HAZOP), Safety Integrity Level (SIL)/Instrumented Protective Function (IPF) study, Fire and Explosive Risk Analysis (FERA) and Fire Protection Analysis (FIREPRAN) study. The paper covers the documentation of ALARP demonstration into a Design HSE Case. Major Accidents Hazards (MAH) in the TPO facility are identified using the Risk Assessment Matrix (RAM). A systematic and structured Hazards and Effects Management Process (HEMP) is applied in the design of the TPO facility and the risks associated with MAHs are actively and systematically reduced to ALARP. The effectiveness of all barriers and controls for each MAH are evaluated and complied with the set criteria (Bow-tie assessment). If the HEMP assessment determines that a barrier or risk management of a MAH is only partially effective, further remedial action and effort is done to close the gap. Besides, Safety Critical Elements (SCE) and their performance standards are identified and developed as a key input to the Asset Integrity Process Safety Management (AIPSM) in the operations phase. Finally, the TPO facility design on a plot size of 70m x 70m pad was accepted for construction and trial production. Further improvement study and optimization has been ongoing including taking other unconventional gas (UCG) best practices and learning into the development planning.

Abstract Carbon capture, utilization, and storage (CCUS) in geologic media have been identified as an important means for reducing anthropogenic greenhouse gas emissions into the atmosphere (Bradshaw et al., 2006). Several geologic settings are appropriate for geologic storage of carbon dioxide (CO2), including depleted oil and gas reservoirs, deep brine-saturated formations, CO2 flood enhanced oil recovery (EOR) operations, and enhanced coalbed methane recovery. The U.S. Department of Energy (DOE) is pursuing a vigorous program for demonstration of CCUS technology through its Regional Carbon Sequestration Partnership (RCSP) Program, which entered its third phase (Phase III) in October 2007. This phase is planned for a duration of ten U.S. federal fiscal years (October 2007 to September 2017), and its main focus is the characterization and monitoring of large-scale CO2 injection into geologic formations at CCUS sites. The Plains CO2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center (EERC), is one of seven regional partnerships established under the RCSP Program. The PCOR Partnership region includes all or part of nine U.S. states and four Canadian provinces (Figure 1) and is made up of numerous private and public sector groups (Figure 2) working to identify the most suitable CO2 storage strategies and technologies, aid in regulatory development, educate the general public, and investigate appropriate infrastructure for CCUS commercialization within its region. The Phase III program undertaken by the PCOR Partnership includes two commercial-scale projects that are of immediate interest to the oil and gas industry, namely the Fort Nelson carbon capture and storage (CCS) feasibility project and the Bell Creek combined CO2 EOR and storage project.

Abstract Hydrocarbon exploration is a complex, risk-based process based on uncertain scientific data. Decision makers are faced with different types of decisions during different stages of the exploration workflow. Relevant data reside in structured and non-structured repositories. Most data are spatially located and are connected through complex spatial relationships which make the data harder to model and visualize. This case study describes the features of a novel web-based decision support system used at Saudi Aramco for hydrocarbon exploration. This new software allows the regional geologists to outline the play and assess the risks and attributes. It guides explorationists through proper risk assessment and probabilistic uncertainty analysis of the proposed prospects and leads. All these assessments are compared against the play and regional trends. The risk and uncertainty of volumetric computations are handled using Monte Carlo simulation. Collaboration and knowledge sharing features help in reaching group consensus and reducing uncertainty. After drilling, the system captures post drill analysis which helps in identifying areas of poor predictive performances and possible remediation steps can be taken. This will in turn help in reducing risk and uncertainty of proposed prospects. Finally, the system provides an integrated view of the heterogeneous data and offers spatial analytical techniques such prospect historical analysis and prospect depth analysis. Explorationists can create ad-hoc queries across the entire dataset to uncover trends and anomalies and then drill down to the details. Using charting tools and GIS analytics the data can be further analysed to verify whether trends are real or anomalies explained. Introduction Although estimates of yet-to-find hydrocarbon resources have increased over the last few years, much of this is high-risk and high cost like deepwater exploration [1]. Driven by growing economies, demand is increasing, in turn necessitating an increase in exploration activities. As observed by Hailey [2], exploration requires large capital investments and is by nature high risk - this kind of activity should be supported by a reliable decision support system. Given the amount of uncertainty, explorationists have many decisions before reaching the conclusion whether to drill a well, starting from play selection through seismic surveying and prospect evaluation. With the amount of capital and labour costs associated with exploration along with the large number of different options to be considered, a decision support system (DSS) is important for optimizing the targeted goals. The role of the DSS is not to make decisions, but rather to facilitate the decision making process by highlighting trends and patterns which provide a guide to reducing the risk element in these decisions. In Saudi Arabia, the national oil company of Saudi Arabia, Saudi Aramco, has increased exploration activity concentrating on frontier and emerging areas [3]. These ventures are high risk, and could greatly benefit from a decision support tool. Development of such an exploration decision support system would have to address a several issues within the computing environment. These would include multiple disparate data sources, addressing the spatial dimension of the problem and dealing with risk and uncertainty.

Abstract Kuwait Oil Company (KOC) has 85 crude oil aboveground storage tanks in its Tankfarms for the storage of crude oil prior to export. These tanks have storage capacities ranging from 162,000 to 597,500 bbl. (US). Hydrocarbons leaks / spillages resulting from tank failures, if any, could be very expensive and could pose serious fire hazards apart from major environmental issues. Therefore, in order to carry out a comprehensive assessment of the tanks to prevent any impending failure, KOC decided to adopt Risk Based Inspection (RBI) approach to evaluate the risks associated. With the aging tankfarm facilities and the changes in oil production processes, it became even more important to ensure the reliability of to ensure the reliability of tankfarm facilities from the viewpoint of "just in time maintenance" and regulatory requirements. The outcome of the evaluation enabled formulation of inspection strategies to mitigate these risks for improving asset integrity. A qualitative RBI methodology was established and the procedure was developed in-house based on the guidelines in international standards (API, NFPA). The procedure was then used to perform the RBI study of each individual tank in KOC Tankfarms. A workbook was developed to carry out the risk assessment of the tanks as per API RP 581 and the RBI assessment results were presented in a risk matrix. For carrying out the risk assessment, the tank is divided into three sections viz. the Bottom Plate, the Shell and the Roof and each section is subjected to risk assessment separately. Relevant damage mechanisms are considered for each of the sections. The RBI analysis includes the information on original design, operation & maintenance, damage mechanisms, timing the failure of individual evaluated components, condition inspections, process condition, NFPA (National Fire Protection Association) rating for service fluid and current operating conditions. RBI study recommendations include the suggested improvements to the inspection program and maintenance schedules to enhance the asset life-cycle. This paper describes the entire Tank RBI process adopted at KOC, some interesting findings of the RBI study and the recommended Asset Management Strategy for the Tankfarms. 1. Introduction 1.1 Brief of KOC Facilities Crude oil from oil wells is transported to the Gathering Centre (GC) via a number of flowlines. The Gathering Centre processes fluids to separate gas, water and salt associated with oil before pumping to the Tankfarms. The crude oil processed at various Gathering Centers of Kuwait Oil Company is transported through the transit pipelines to the Tankfarms. Over 85 tanks in the Tankfarms receive crude oil with a minimum API of 30.5 from the incoming transit pipelines via a Central Mixing Manifold. The tanks are equipped with automatic level gauges, Motor Operated Valves, firefighting facilities and manual oily water disposal system. The crude oil is stored at these Tankfarms prior to export. KOC sets the production targets on the basis of continuous market demand.

Abstract In the aftermath of the massive oil spills in the Timor Sea and the Gulf of Mexico there is heightened wariness and many questions about the sustainability of offshore exploration for oil and its marine transportation. Traditionally, oil spill management has been a reactive rather than proactive process involving containment, dispersal, capture, and possibly beaching and clean up of oil spills. There was little forward planning on how to minimize and manage oil slicks to reduce the environmental impacts. This is no longer accepted by the public and so new proactive approaches are needed. A new risk assessment approach was developed and is being implemented in the Gulf of Thailand, but the method could be applied anywhere. The approach combines advanced computer modeling, integrated with geographic information systems and environmental sensitivity indices. In this paper a process for identifying, assessing and minimizing environmental risks from oil spills is introduced based on a recent work in Thailand. The paper includes maps and model predictions of risk areas from a hypothetical spill and a comparison of the results of the new approach with those of the currently accepted method of risk assessment in Thailand. The method will be beneficial in refining the mapping of risk areas in sensitive and confined areas such as bays. It will add rigour to the analysis of the oil spill risk component of environmental impact assessments that are mandatory for the exploration and transportation of oil. It will also be helpful in developing emergency response plans using window of opportunity to mobilize for a spill event. The novelty of the approach is the use of overlaying model projections from both a source and receptor perspectives. Introduction In the aftermath of the massive oil spills in the Timor Sea and the Gulf of Mexico there is heightened wariness and many questions about the sustainability of offshore exploration for oil and its transportation across the seas. Traditionally oil spill management has been a reactive rather than proactive process involving containment, dispersal, interception, capture, and possibly beaching and clean up of oil spills. There was little forward planning on how to minimize and manage oil slicks to reduce the environmental impacts until the major catastrophe of the Exxon Valdez event in Alaska over 20 years ago. Although planning has become much more thorough since, the recent catastrophic spill in the Gulf of Mexico has put renewed pressure on increasing the level of preventative planning for such events. Therefore, new proactive approaches are being called for which are more rigorous and provide greater environmental security and protection. In this paper an integrated process for identifying, assessing and reducing such risks is discussed. Types of Risks Risk Sources - Sources of risk include exploration wells, floating production storage and offloading facilities, shipping, oil containers and fuel releases from ships. Blow out of oil wells and accidents at the platforms are dramatic and headline news as was the case of the Deep Horizon event in the Gulf of Mexico. Spills during the transfer of oil to and from floating storage facilities or at docks usually involve less volumes, but they occur more frequently than well blow outs. The loss of fuel from ships, either through accidents, leakages or deliberate dumping, is by far the most common form of oil spill at sea. However they involve the least amount of spilt oil volumetrically. The key issue with risk sources is the need to understand the areas which may be affected by spills.

This reference is for an abstract only. A full paper was not submitted for this conference. Primary Category: Managing Risks and Uncertainties Abstract The Chemical, Petrochemical and Oil& Gas industry has had an excellent safety record when compared with industry as a whole1. Nevertheless few major incidents like MIC gas leak in Bhopal, LPG plant explosion in Mexico etc. with heavy loss of life led to public concern about the hazards of process industry, resulting in legislations requiring manufactures to demonstrate that appropriate safety measures are taken. This led the industry to resort to predictive Quantitative Risk Assessment Technique (QRA) The Piper Alpha and Alexander Kielland accidents led to prescriptive regulations on use of QRA in process industries in both UK and Norwegian sector of North Sea. As a result, interest in use of QRA technique for assessing safety of process plants has grown considerably. Overall use of Quantitative Risk Assessment has continued to increase although some countries still remain skeptical about of the value of use of QRA. A major difficulty faced by industry in using QRA is setting Risk Tolerance/acceptance Criteria. What is the Target Risk Acceptance Criteria to be followed? Is there a Universal Risk Acceptance Criteria? A literature search reveals that different regulatory bodies world over have recommended different acceptance criteria for Individual Risk. The Criteria for few important countries are presented in Table-1. There is wide variation in Acceptance Criteria for Societal Risk also as presented in Figre-1. As it is evident from the Figure, different nations have adopted different risk aversion factors. UK and Hong Kong did not consider any risk aversion factor and slope of the lines is -1. Netherlands and Denmark have adopted a more stringent risk aversion factor as indicated by the slope of -2 for these lines. Australia has adopted moderate risk aversion factor as the slope of the line is between -1 and -2. On the contrary certain developed countries like USA, France, and Germany etc. do not prescribe any Risk Tolerance Criteria both for individual and Societal risk. Further, there are great uncertainties in risk estimation.2, 3 In view of the above problems, industry finds it difficult to arrive at a Risk Criteria. In general, the industry looks for advice from QRA consultant on risk criteria and consultant seeks guidance from industry to define the risk criteria. Most industries, particularly in developing countries, are not well equipped to understand the complexities involved in risk estimation and selection of appropriate Risk Tolerance Criteria relevant to local political, social and economic conditions. The Criteria recommended by the consultant may be very stringent with little relevance to the local conditions leading to problems for the industry with recommendations requiring heavy demand on scarce resources. Knowledge of complexities involved risk estimation, the end use of the risk estimates, the origin, basis and development of Risk Acceptance Criteria are prerequisite for the Industry to be able to decide on the Risk Acceptance Criteria in an effective manner relevant to the local conditions. In order to assist the industry, this paper Analyses the problems with quantitative risk estimation and uncertainties associated in the estimation, Critically reviews the Risk Acceptance Criteria recommended by different regulatory bodies, and Provides guidelines, based on author's experience, for path forward in setting appropriate Risk Acceptance Criteria relevant to the industry objectives. It is expected that the guidelines along with the discussion on risk estimation and uncertainties will make the life of operator a lot simple in making a decision on Risk Acceptance Criteria. Literature cited Institution of Engineers, UK, Risk Assessment in Process Industries, (Ed… Robin 1996). Kurt Lauridsen, Igor Kozine, Frank Markert Aniello Amendola, Michalis Christou, Monica Fiord, Assessment of Uncertainties in Risk Analysis of Chemical Establishments The ASSURANCE project Final summary report, Risø National Laboratory, Roskilde, Denmark, May 2002. D. Veeranna, "Quantitative Risk Assessment - A Decision Making Tool in Process Industry on Safety Issues", Fourth International Professional Development Conference on Occupational Health, Safety, Environment and Loss Prevention, American Society of Safety Engineers, Kuwait Chapter, Kuwait, 15- 17 April 2007.

Abstract The confidence of stakeholders in corporations has been shaken by a series of corporate wrongdoings. Over the past several years, numerous top executives have been found guilty of improprieties such as illegal accounting methods and violating the Foreign Corrupt Practices Act (FCPA) and other anti-corruption statutes. As a result, government authorities in the U.S. and other countries have been expanding their oversight of the ways organizations manage their businesses and the records they generate. Failing to comply with these standards can have significant consequences with the possibility of fines, other monetary penalties, jail time for executives, adverse share price impact and loss of market share. Legal compliance is a challenging and essential element of corporate governance. Companies pursuing opportunities in developing economies often face additional hurdles in fashioning an effective compliance program due to unfamiliar geographies, numerous complex local laws, cultural barriers, and political and financial complexities. Improper business conduct in such locations can expose a company to unforeseen risk, reputational damage and civil and criminal penalties. As a result, organizations should work to ensure that their operations meet the highest standards of both ethical behavior and legal compliance. In the current economic, regulatory and social climate, compliance risks have propelled integrity, good corporate governance and effective and efficient compliance management to a top business priority. Baker Hughes Incorporated (BHI) firmly believes that ethics is essential for sustained high business performance. To ensure that it meets these challenges, BHI has developed a global best-in-class compliance program that can serve as a model for other companies facing formidable global compliance challenges. BHI's compliance program consists of a rigorous, customized system of corporate governance. The program requires all employees to comply with the law, the company's core values—integrity, teamwork, performance and learning—and its business code of conduct. BHI's compliance program has a special focus on legal compliance, financial compliance, and health, safety and environmental compliance, all of which are well defined and articulated through every part of the company. The compliance culture that has evolved at BHI is based on the critical concepts of prevention, detection and response. In terms of specifics, BHI's compliance program: establishes proper tone at the top; assigns oversight and management responsibility for the compliance program to a vice president and chief compliance officer with active oversight from executive management and the board of directors; establishes clear global compliance standards and procedures; assigns compliance responsibility and accountability to line managers and all employees; provides mandatory, customized training at all levels; provides a robust and easily accessible reporting system for compliance violations to employees and other stakeholders; and manages and investigates all allegations of misconduct and noncompliance in a timely and competent fashion. A key component of the company's compliance program is FCPA compliance. This paper outlines effective processes and procedures that have been employed by BHI, both from a compliance as well as commercial perspective, which can be successfully utilized for managing complex international oil and gas businesses, while fulfilling the obligations of a good corporate citizen.

Abstract In the planning of a new appraisal well on an HPHT field on the Norwegian shelf, pressure control was at an early stage identified as a challenge. The pressure margin was expected to be narrow and pore and fracturing pressures were uncertain. This represented risks related to fracturing and losses and to kick and ultimately loss of well control. To explore the extent of the risk, understand the most important factors contributing to risk and provide a basis for reducing risk through decisions in the operation planning, a quantitative risk analysis was commenced. Pressure control physics and the impact of uncertainties were explored through Monte Carlo simulation using the KickRisk analysis tool. With this tool probabilities are used to describe the uncertainty related to a number of operational, equipment related and geological pressure components. The output from an analysis reflects the ability to stay within the safe operational window during drilling, in terms of well specific kick and fracturing probabilities. The relative risk contributions from the different operational phases and from different kick and fracturing mechanisms in each phase are included. This paper describes the application of the KickRisk analysis tool on the HPHT well. Specific attention is drawn to how the analysis supported the identification and selection of measures aiming at minimising pressure control risk. Such measures include risk-based mud weight selection, reinforcement of procedures and preparation of decision rules with respect to the outcomes of formation integrity testing and pore pressure measurement during drilling. 1. Introduction Pressure control was a key issue in the planning of the reservoir section of an HPHT appraisal well on the Norwegian Continental Shelf. Narrow pressure margins and considerable geologic uncertainties involved risk of mud loss, kick and ultimately blowout. Forthcoming decisions related to selection of mud properties and operational procedures would be a challenge, and the overall risk level of the drilling operation unclear. It was decided to undertake a quantitative risk analysis (QRA) with focus on pressure control in order to improve the understanding of the risk picture and to obtain a stronger basis for decision-making in the development of the drilling program. The objective of this paper is to present the stages of the QRA in the well planning process, the results and their applicability as decision support for the project. The appraisal well was to be drilled with a jack-up rig, i.e. excluding heave effects on the bottom hole pressure (BHP). The reservoir section was planned drilled with 8 ½" drill bit, with the 9 5/8" casing set above the reservoir formation. Originally, tripping out of the well was planned with a slug and no circulation. It was first assumed that the well would be completed with screens. Later it was decided to run 7" liner. At the time of writing this paper, the drilling of the well was ongoing, but the reservoir section was still not commenced. The QRA was performed by use of the KickRisk analysis tool. This tool is based on a pressure control model. Factors that influence the BHP throughout the various phases of the construction of a well section are decomposed. The model includes down hole, fluid, equipment and operator-related aspects and their impact on hydrostatic, friction and surge/swab pressure effects. The analysis implies gathering of input on the uncertainty of these quantities in terms of probabilities and probability distributions. By Monte Carlo simulation the resulting probabilities of entering a state of underbalance with the pore pressure (kick) and of exceeding of the fracturing pressure (fracturing) are derived, and the factors that are main contributors to risk may be identified. The analysis was performed in 3 stages. Most of the input was gathered in the first stage and an overall risk picture was established. The two latter stages were updates on decisions on equipment, design and procedures introduced through the project. Some more details on the analysis tool are included in Section 2. Section 3 expands on the analysis process and the analysis results. Conclusions are summarised in section 4.

Abstract Escalation of per-barrel crude prices is expected to continue on an inflation adjusted basis in the foreseeable future according to most analysts. Rising prices are largely attributed to market forces fueled by surging world economy and growing demand, particularly in Asia and Middle East. Relatively flat rates of exploration and exploitation success have been unable to keep pace with that growth, leading to tight supplies. Politics, weather, speculation and other factors further contribute to supply uncertainty. International Oil Companies (IOCs) face competition from other IOCs as well as from entrepreneurial national oil companies (NOCs) aggressively looking to develop assets domestically and overseas, and reserve replacement remains a challenge as suppliers try to gain access to incremental upstream resources in order to meet growing demand. NOCs no longer remain in a simple asset management role for domestic resources; rather, many entrepreneurial NOCs have joined the fray alongside IOCs in pursuit of E&P resources outside national boundaries. Besides straight E&P initiatives, associated major projects and services are also expanding internationally. With the growing number of international ventures in the petroleum and energy market, the significance of market entry risk assessments has also increased correspondingly. Timely, objective basis for decision-making provides a distinct business advantage in a dynamic global market. Consistent application of the Rajan-Vikas model 1, 2 enables rapid screening of candidate markets as relevant to the project or initiative. Other model artifacts include risk characterization profile for the various countries, and relevance profiles for each project or initiative. Different forms of these various profiles, in turn, lend themselves to mining for opportunities once a substantial knowledgebase is built. The focus of this paper is on potential opportunities exposed when the Rajan-Vikas model is applied for market entry risk assessments. Introduction The global energy balance is changing, as growth rates slow down in the western developed nations, while countries in Asia and the Middle East are developing rapidly, and energy demand has also grown correspondingly. Oil consumption in OECD Europe, for instance, increased from 13.7 MMbbl/d in 1990 to 15.5 MMbbl/d in 2005, net 1.8 MMbbl/d. Over the next 15 years that oil consumption if expected to only increase 0.1 MMbbl/d. On the other hand, oil consumption in India, China, Russia, and FSU countries is expected to grow dramatically. These global shifts in demand growth will define the future oil markets.

Abstract With the increasing use of ALARP principles in oil and gas safety studies to reduce the tolerable risks to As Low As Reasonably Practicable level, there is a need to understand the use of those principles with respect to (a) the level of uncertainty of data and (b) the risk criteria. Because of the level of uncertainty of data it becomes unclear which tool to be used for ALARP demonstration. As far the application of numerical risk criteria is concerned, it is not always correct in some cases. Thus the demonstration of ALARP and the risk criteria used should be justified by the categorization of risk which may be qualitative, semi-quantitative or quantitative, and the available data. For quantified risks, the intensification of ALARP demonstration will depend on the available data and the level of risk reduction to be achieved. Overlooking of such issues could lead to either inadequate analysis or over-analysis of risk resulting in companies burdened with extra cost for implementation of recommendations. This paper suggests a structured methodology for the ALARP demonstration and its 'level of intensification', to address the issues stated above. Examples from previous risk assessment studies undertaken for various oil and gas companies have been taken and the proposed methodology is applied in the management/ALARP demonstration of both acceptable and tolerable risks. In the end, the paper demonstrates the benefits of using the proposed methodology. The paper also addresses some common misconceptions regarding the ALARP principle. Abbreviations Used ADNOC Abu Dhabi National Oil Company ALARP As Low As Reasonably Practicable CBA Cost Benefit Analysis DA Decision Analysis DF Disproportionate Factor EMBOT Extended Modified Bow-Tie Analysis HSEIA Health, Safety and Environmental Impact Assessment HSEMS Health, Safety and Environmental Management System IAD Intensification of ALARP Demonstration MBOT Modified Bow-Tie Analysis QRA Quantitative Risk Analysis / Quantified Risk Assessment RRM Risk Reduction Measure Introduction This paper addresses process related risk management by application of ALARP demonstration. In order to address the topic, i.e. ALARP Demonstration and its Level of Intensification, this paper begins with an explanation of the ALARP principle. It highlights some of the principles outlined by Health and Safety Executive (HSE), UK. Some misconceptions on the application of ALARP are also discussed. The paper outlines two problems faced during an ALARP study, namely, uncertainty of data and risk criteria. The points to be kept in mind while assessing such problems are discussed. Hence an assessor may find this useful while dealing with risks to be reduced on the principles of ALARP. The paper suggests that the application of ALARP demonstration tools and methods should depend on the categorization of risk. The tools used to demonstrate ALARP will vary depending on the level of risk reduction as well as the expression of risk (qualitative / quantitative). Hence the term 'intensification' is used for the assessor to know if a justified level of demonstration is being sought for the appraisal of risk reduction options. Thus the question 'how deep to dig' should be answered before proceeding with the demonstration. Some examples of the demonstration tools have been included but these are not intended to be prescriptive.