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HPHT well environments present design & operational challenges that could potentially translate into well failure with high consequences. Several risk elements can combine into a complex hazard causing serious threat to well design & integrity. Risk elements could be complex downhole environment, material deration, material incompatibility with the completion/packer fluids and other treatment fluids, metallurgy imbalances etc. This case study presents early life production tubing integrity failure highlighting gaps and suggestions to adopt an integrated risk mitigation approach. A 5,700 m TVD keeper HPHT exploratory well was drilled in north of Pakistan with reservoir pressure, temperature exceeding 10,000 psi and 320°F respectively. Matrix acidizing was required to remove near wellbore damage in the targeted carbonate reservoir. Initial kick start stimulation efforts resulted in tubing-annulus communication indicating compromised CRA super 13CR completion string integrity. Workover followed wherein another early life completion string failure occurred. Consequently, comprehensive analysis was carried out to determine failure root causes using a systematic fault tree analysis approach. Failure investigation consisted of two broad scopes: a) Scrutinize well design against established industry standards and best practices for HPHT wells and; b) Completion string material metallurgy tests to evaluate compatibilities with exposed well & treatment fluids, bottom hole environment and assessment of all possible risk scenarios that by itself or in combination with other risks could cause material failure. Further, detailed study work included describing bottom hole environment comprehensively, various types of corrosion risk assessments including evaluation of environment assisted cracking risks, acid inhibitor efficiency evaluation, completion/packer fluid selection, fluid compatibility assessment and fluid additives degradation at high temperatures. Mill manufacturing processes, susceptibility of CRA material passive layer because of austenite percentage were also looked-into. Based on systematic approach and extensive in-depth analysis, key observations were drawn. These observations were further investigated with material testing and possible root cause failure risk factors were arrived at. Conclusions were drawn highlighting primary and secondary failure root causes. A new basis of design and qualification protocols was proposed to mitigate various risks to ALARP. Holistic HPHT well design approach is found to be lacking pan industry as the complex failures risk mitigation information is either not available or is discrete. Operators venturing into HPHT for the first time are challenged to comprehend requisite steps required to mitigate the risks to ALARP. Therefore, the paper aims to provide an integrated approach for completion metallurgy selection and test qualification requirements for stimulation and completion fluid in conjunction with the downhole environment.

The decision to carry out a water or gas shut-off treatment in an oil well, is of concern to the petroleum engineer. The engineer must choose an explicit course of action with the information at his disposal. This decision however, has consequences that cannot be predicted with certainty. Water or gas shut-off treatments don't turn out the way we plan, because the outcome could be a success or a failure. Traditional economic method of evaluating water and gas shut-off decisions typically involved cash flow considerations, such as net present value, which combine single point estimates to predict a single output. This method is deterministic, ignores the quantitative consideration of risk and uncertainty as one could be conservative with some estimates while being optimistic with others. The combined errors in this approach frequently lead to results that are significantly different from reality. Thus, a technique that will overtly include uncertainty in our estimates to generate results with all probable outcomes will aid the engineer in making an informed choice. In this paper, the expected value economic concept is used for the mutually exclusive events of water and gas shut-off treatments. Through expected value and standard deviation of a random variable, Monte Carlo simulation and decision tree analysis, incorporating uncertainty in oil price, production forecast and operating expenses are used to evaluate the expected return and risk associated water and gas shut-off opportunities. This approach minimizes the chances of failure and provides useful insights for water and gas shut-off economic decision making.

The nature of operations in the petroleum industry involves a significant amount of process and personal safety risks. Industry operators and service providers desire to achieve the safety goal of no fatalities or harm to personnel, and no damage to assets and environment. Most operating companies and service providers have over time developed well-structured frameworks for Process Safety Risk Management. Aspects of personal safety especially operations-related are also well managed. A significant number of incidents have resulted from human factors related to stress and fatigue. Fatigue is a state of sleepiness with the associated lack of mental alertness caused by sleep deprivation. It is imperative that the industry recognizes the threat posed by fatigue and put the right measures in place to minimize the associated risks. This paper intends to raise awareness on the impact of fatigue in the petroleum industry and recommend a framework for Fatigue Risk Management (FRM). A structured framework entails embedding of FRM Systems, which include studies, gap analysis, closure plans, and development of FRM plans, implementation, audits, and reviews. The FRM system will ensure a safe working environment using a risk model to review outcomes and recommend actions. The embedment of this system which is based on Safety Management System (SMS) in the workplace ensures appropriate mitigations, effective controls, timely implementation, periodic audits and reviews. This system may be deployed in all areas of petroleum industry operations spanning Exploration and Production to the downstream sector. Similar models have been deployed in other industries with success.

The explosion at BP's Texas city (March, 2005), macondo deepwater horizon blowout (April 2010), an Olefins Plant reboiler rupture and fire (June, 2013) and the explosion of a Refinery in Torrance (Feb, 2015) are all widely known major incidents that have resulted in major loss of lives, damage to the assets and the environment. These looses worth millions of dollars not counting the loss of lives shows that process safety barriers was compromised. How then can we be more certain that these incidents does not occur again in our plants? What indicators can we look out for? Are our risk assessment for process safety accidents properly assessed with adequate barriers defined to prevent the occureance of major incidents? This paper focuses on the technological risk assessment (scenario based assessment; a Total E&P major risk assessment methodology) carried out on OML 99 for the management of major risk activities. To study, manage operational activities, hazards to people, environment and assets were identified and assessed in a systematic methodology and associated risks evaluated. The objective of the process was to proffer risk reduction measures and ensure that sufficient barriers exist to prevent major risk scenarios. The outcome of the technological risk process was the major risk register containing the top ten scenarios (Major Risks) showing scenarios, barriers/controls in preventing and protecting the occurrence of these major accidents with an action plan containing a list of approved risk reduction measures at the end of the ALARP demonstration. As examples, the paper communicates the barrier management strategies between the major risk register, the site emergency response plan, safety critical barriers and management inorder for Field Operations management to ensure that the asset operational Chain of Command identifies and manages the major risks of their installations in order to prevent the occurrence of major incidents.

The study focused on evaluating the Health, Safety and Environment (HSE) performance of selected Oil servicing companies (X, Y and Z) engaged in Logistics, Mud logging and Engineering services respectively in Rivers State, Nigeria. This aim was achieved by determining the awareness level of Health, Safety and Environment Management System (HSE MS) and performance/practice level of HSE MS respectively. Two sources of data were both used in this study. The primary source were from questionnaires distributed to 150 participants, out of which 120 were retrieved from 42 participants in company X, 40 in company Y and 38 in company Z representing 80% response rate. The awareness and performance levels of HSE MS were assessed with ten questionnaire parameters each respectively and their judgments rated Yes (3), No (2) and Undecided (1). This Likert approach was to facilitate the evaluation of Kendall's coefficient of concordance (W), representing the concordance level among participants. The results revealed average levels of awareness (79%) and performance/practice (64%) of HSE MS respectively among the companies except for company Z. Gaps identified included lack of awareness on what governs the integrated HSE MS, lack of provision of hygienic environment and non-availability of safe equipment and PPE. Company Z had deficiencies in providing a good system for communicating HSE issues, providing permit to work (PTW), conducting HSE induction/training, providing incident reporting procedure, ensuring contingency plans are made available and maintaining a good system for managing employee's health. The secondary data source were from the HSE MS Audit unit of the companies selected which showed that company X had an overall performance of 77% which indicated a good level, company Y had an overall performance of 64.3% which is a fair level and finally, company Z had 30% performance level which is unsatisfactory. Kendall's analysis showed a high level of agreement on both awareness (0.90) and performance (0.99) levels respectively. The study recommends training of employees, provision of an environment with good hygienic conditions, and provision of safe equipment and personal protective equipment (PPE) for all companies. Provisions for contingency plans permit to work (PTW), and HSE review meetings should be emphasized by company Z. The findings and recommendations of this research will be a yardstick to these companies and other related companies in implementing HSE MS as business integration in quality and risk management.

Appraisal adds value to potential developments by changing key development decisions (well count, subsea infrastructure requirements, development sequence, etc.), and this value can be quantified using value of information (VOI). The value of perfect information is readily evaluated but, unfortunately, all real world data is imperfect. Quantifying the value of this imperfect information requires assessment of either (i) the likelihood of the appraisal activity correctly resolving the value of an uncertainty, or (ii) the impact of the activity on the post-appraisal uncertainty range, both of which can be problematic. Traditional value of imperfect information analyses tend to focus on resolving only a single uncertainty and becomes difficult to apply as the number of uncertainties addressed by a single appraisal activity increases. This paper describes a fit-for-purpose probabilistic approach to enable the rapid evaluation of perfect and imperfect value of information for a range of appraisal alternatives. The workflow is demonstrated through its application to a recent deepwater appraisal well which included an extended well test selected as the preferred activity from amongst a range of alternatives (including conducting no further appraisal). The workflow uses a Monte Carlo spreadsheet tool to generate gas in place (GIIP) and estimated ultimate recovery (EUR) estimates for individual reservoir elements, which are then aggregated to field level estimates. A large number of individual trial values are captured and interrogated in conjunction with a set of heuristics to allow the rapid generation of probabilistic development plans (without needing to rely on a small set of deterministic realisations). Distributions and dependencies defined in the spreadsheet can be readily altered, enabling robust evaluation of the impact on EUR and preferred development plan for each appraisal alternative and outcome (low/mid/high). The EUR and development plan are then used in an economic model to quantify the value added by each appraisal activity. The highest value appraisal activity, in this case the appraisal well with an extended well test, was executed and a post-appraisal lookback was completed to review the value of information analysis once the appraisal results were available.

Since LNG (Liquefied Natural Gas) is a combustible cryogenic liquid and as such presents specific safety hazards, the safety of LNG utilization has become an issue that requires a comprehensive study on the risks. Hence, various safety aspects connected with the operation of LNG need to be analyzed. The purpose of this paper is to review recent researchers' LNG safety studies and analysis. Specific safety characteristics of the equipment involved are incorporated in the analysis. The analysis of important risks show that at pressures near atmospheric, the hazards of LNG are comparable to those of conventional liquid fuels such as gasoline. At higher pressures, it behaves more like a combustible gas liquefied by compression. Also reviewed in this paper is the state of the art in modeling important LNG Hazards (like pool and vapor fires modeling). Totally, this paper identifies different possible risks in and out LNG plants and describes the results obtained from modeling of identified issues.

Safety risks of drilling operations exist widely because of the hostile environment, ageing equiments, more challenging wells, human errors, etc. Failure to control or eliminate the safety risks may affect the drilling safety and lead to drilling accidents, resulting in enormous economic losses, or even casualties. Previous drilling accidents had shown great challenges of safety risk management, such as outdated management ideas and tools, poor awareness of safety risks, lack of effective safety risk information sharing and incomplete risk management system. In this paper, the potential safety risks associated with drilling facilities, workers, and management are figured out, and the corresponding risk management measures are formulated. Meanwhile, the guidelines for safety risk management of drilling operations are established. In addition, the guidelines are combined with the information technology, and the Web and mobile versions of the intelligent safety risk management software of drilling operations are designed and developed. The safety inspector in drilling sites can use mobile terminals to identify the drilling risks, being recorded in the form of text, pictures, video and other documents, and choose the risk control and mitigation measures. The safety management staff in the company can monitor the results of chosen measures in time by using the Web version, and provide effective and timely technical support for the field’s safety risk management if necessary. With the use of the intelligent safety risk management software of drilling operations, the two-way communication and safety risk information sharing between drilling sites and drilling safety management departments can be realized. A complete drilling safety risk management system can also be gradually developed in the process of risk identification, record, report, analysis, control, mitigation and prevention. The intelligent safety risk management software of drilling operations has been applied in some oilfields, and reveals excellent application prospects. Being an intelligent management tool, the software system can significantly improve the safety risk management efficiency, and finally realize the informational management of safety risks in drilling operations.

Most behavior based safety programs (BBSP) are implemented after the fact of either a major accident, a change in company organizational structure or as a result of a dip in company fortune. It is common practice to rely on historical data, empirical analysis and observable trends while embarking on the implementation effort. The oil industry safety management systems have evolved and have been driven by the need to embed a culture that aligns with corporate vision and objectives. A common strategy in the exploration and producing industry is to create a culture of Safety First where everyone especially in the operations zone is empowered to stop the Job. This a great fallacy because human factors are not factored into the development of these program. This paper will therefore highlight these issues. This paper is based on documented case studies and the author's operational experience in different companies and projects. Because most BBSP discounts the importance of human factors, it is typically met with homeostasis. Many reasons can be advanced for this observation and clearly the top reason will be that change is not natural to man and the individual's culture, experience, personality and change intelligence will all contribute to either make him or her a pro-change or an anti-change agent. This paper will elaborate on the following pitfalls in the process of implementing a BBSP to wit: ❖The fallacies of HSSE Data Mining and Management.❖Analysis and Inferences of Organizational Structures and Cultures.❖The knowledge of a work team and indeed an organization is not always additive when behaviors are the focus of attention.❖Leadership is an aberration and power distance elimination is the delimiter of the success or failure of any BBSP.❖The half-life of learned lessons and why the same incidents recur within the same industry despite the technologies available for knowledge dissemination. While HSSE programs are useful tools for communicating and implementing corporate safety visions and goals amongst others its limitation derives from the fact that it depends on the peripheral human behavior domain to be successful. This paper identifies all the limitations and proffers a methodology for implementing human factors backed BBSP that avoids the pitfalls.

Health, Safety and Environment (HSE) reporting is defined as the recording of all unwanted or unplanned events/occurrences whether or not they resulted in injuries to people, damage to assets, harm to environment or have the potential to do so. In Nigeria, recording and reporting of accidents and ill health at work is a legal requirement under the Mineral Oil Safety Regulations (MOSR) 1997 and internationally, under the Reporting of Injuries, Diseases and Dangerous Occurrences Regulations (RIDDOR) 2013. In HSE reporting, there are leading (proactive) and lagging (reactive) indicators. "Leading" indicators are preferred because they record performance before the top event and therefore helps create a safer work place, reduce lost time, increase productivity and improve company reputation. Identification of situations/actions that can lead to actual incidents /accidents in the work place and removing them ahead of time is key; It also helps to identify weak links and provide focus areas and efficient channelling of resources and creates learning opportunities in the workplace and proactively prevents actual incidents from occurring. These leading indicators include Unsafe Acts (UA), Unsafe Conditions (UC) and Near Misses (NM. This paper will discuss contributions of proactive reporting in relation to good HSE performance and learnings, over a couple of years in Oil & Gas Company. It will also demonstrate how application of LEAN methodology (an efficiency minded and quality-oriented process) helped to overcome the challenges with reporting and hence improved the quantity, quality and learning from past incidents. The outcome of this project, has been critical in creating a culture of pro active safety management and reduction in significant safety incidents

This paper, describes shortcomings of prescriptive regimes and the emergence of and progressive internationalisation of what is variously described as a goal setting or risk-based approach. Specifically the adoption of the "safety case regime" and how it can be used to improve standards of safety and used as a decision support tool is described. The introduction of a "safety case regime" has taken the industry several years to fully appreciate and effectively apply it as a tool for improving standards of safety. The development of a safety case can provide essential insight into the risks facing an installation and the controls required to manage them. How this information is then used most effectively in operations is still an area for improvement; however there are some key approaches that can provide valuable insight and information to operators on a day to day basis. Historically, most regulatory safety regimes have prescribed rules and standards that must be achieved, with varying degrees of enforcement. The limitations of this approach have been demonstrated in subsequent major accidents following which it was shown that the law was being complied with. A typical response to such incidents was to amend the regulations; often resulting in unnecessary additional costs, and a detailed focus on compliance, rather than understanding the risks associated with an individual facility and how it is operated. The safety case regime was born out the recognition that such mandated regimes were not effective in preventing major accidents. The use of Bowties as an operational risk based decision support tool is considered with both the benefits and potential pitfalls of this approach being described. This paper builds on extensive experience gained in the North Sea and an approach being developed for use offshore Ghana.

Recently, there have been significant enhancements for well control training. Accidents have motivated and necessitated this improvement. As a result of accident investigation, the IOGP (International Association of Oil and Gas Producers) recommended to define, develop and implement enhanced technical and behavioral practices for well control training coupled with evaluation and certification of the recognized industry certifying bodies. Implementation of these recommendations and improvements is the topic treated in this paper. These enhancements address best practices and add the topic "human factors" to the course. Human factors refer to situational awareness, decision-making, teamwork and dynamics, leadership, communication and performance shaping factors. This paper also outlines traditional well control training. Traditional well control training has typically four levels, each with its own materials, and thereby targets various drilling professionals with different roles on the rig. The highest level course is designed for supervisors, and is required in order to participate in the new IWCF (International Well Control Forum) accredited Enhanced Well Control course. The Enhanced Well Control course has been developed with the accreditation body (IWCF), a drilling contractor (Seadrill) and a training provider (Maersk Training). Having representation of these three entities maximizes the effectiveness of this training in that the interests of the end user, the accreditor and, of course, the service provider are all met within a common and agreed upon framework. Enhanced Well Control incorporates expanded scenarios (setting of cement, running casing, and unconventional well kill methods), specific practices and exercises and behavioral responses. Many topics are covered with focus on teamwork, leadership, decision-making and situational awareness. Case studies and customized scenarios are also treated. These developments in well control training provide a safer and more productive drilling environment.

A real-time production surveillance and optimization system has been developed to integrate available surveillance data with the objective of driving routine production optimization. The system aims to streamline data capture, automate data quality assurance, integrate high and low frequency data to extract maximum value, optimize the design and analysis of commingled well tests, and provide real-time multi-phase well rate estimates for continuous well performance evaluation. A key challenge identified was the need to understand individual well contribution during commingled well tests, as traditional approaches may provide unrepresentative results. Additionally, the well tests are typically infrequent, thus further limiting the reliability of estimated well rates as production system dynamics between well tests are not accounted for. A third challenge recognized was the need for efficient testing procedures in order to minimize deferred production. To address these issues, a fully integrated model of the production system was used, and is driven by a computational algorithm that automatically calibrates the model to real-time sensor data. A new systematic approach was developed to analyze multi-segment commingled well tests simultaneously to improve the accuracy of resulting measurements. Between well tests, a robust regression algorithm is used to continuously adapt and re-calibrate the model when well conditions change. This algorithm can automatically detect sensor bias and apply an appropriate weighting when calibrating the model. In addition, a regularization technique is also used to prevent physically unrealistic changes in the well parameters between infrequent well tests. The technology is currently applied to an offshore deepwater asset and early benefits include a 2% production uplift realized from optimizing gas lift allocation and performing a single well routing change recommended by the technology. Furthermore, more reliable rate allocation to wells has improved the quality of subsurface models used for reservoir management.

Companies on the Norwegian continental shelf (NCS) have in recent years mainly focused on control of the integrity of technical barriers. Against the background of learning from incidents, verification and monitoring activities, both authorities and companies have seen the need to strengthen the work of the management of non-technical barriers. DNV GL and IFE have together with an NCS operator company developed a method to proactively capture factors that have impact on major accident risk in the organisation. The method monitors the use and maintenance of non-technical barriers against major accidents on three levels of management. It is pro-active, and strengthens the management's ability to identify and understand the subtle signals of weakening of non-technical barriers against major accidents. The method may be included in the existing management system; it is based on existing requirements and does not need new systems, resources or expertise. The testing on the three management levels showed that the method is relatively easy to learn, but using the method required understanding. Those who were involved seem relatively quickly to take ownership and see the usefulness of the method. The strength of the method is its ability to support the company's subject matter expertise to interpret ambiguous information, identify weak signals and assemble knowledge into information that can be used to assess the status of non-technical barriers. Based on this, the expertise can prioritize and highlight few and effective measures at all levels of the organization. On the basis of the good experience from the testing, the project recommends to implement the method in the organisation.

When plans for execution of work offshore are prepared, a range of significant risks to HSE are only addressed late in the planning process. This paper highlights and discusses the challenges associated with late risk identification in the planning from the perspective of safe and efficient task execution offshore, and how to enable earlier identification of risks. The paper is based on data obtained from multiple sources based on the principle of triangulation: a literature study of major accident theories, analyses of investigation reports on hydrocarbon leakages, interviews with staff members involved in developing plans for offshore work, and two workshops on the topic of planning with two different operating companies operating on the Norwegian continental shelf. The study suggests that late risk identification reduces the quality of the plans and as a consequence the quality of their execution. Late risk identification leads to a range of inadequacies in planning, e.g. insufficient work descriptions, and relevant information which remains unaddressed during the planning process. These are all factors that can lead to unsafe and less effective task execution. As an example, work with hydrocarbon carrying systems requires end controls in several steps. Such control activities should be included in the job description when the job is established in the systems, rather than identified during the progression of the task execution process. The opportunities lie in earlier risk identification in the planning process and we specify in which phases improvements can be made. The study highlights the importance of quality in planning and how higher plan quality can be achieved through earlier risk identification for work to be executed offshore. This will influence work safety as well as efficiency.

It is inevitable that during a wells life cycle there will be failures or degradation that introduce risk. By applying process safety principles, there are three questions that an operator should ask themselves:Do we understand what could go wrong?What systems remain to prevent this happening?Are we getting the right information to assure us that these systems are working effectively? In terms of well integrity management, questions one and two are dealt with in major accident hazard reviews, leading to well designs that ensure there are adequate barriers between the hazards in the well and the environment. Question three is managed by the verification and assurance of the identified barriers and systems that are aligned with corporate or industry performance standards. This paper suggests a fourth question: 4. Is risk communicated to the relevant people to ensure effective decisions are made, and that the risk is understood and mitigated? Traditionally, a well failure model approach can be used to optimise the risk assessment process with recommended response times to repair specific failures. However, it does not account for the whole asset and the overall level of risk is posed to the installation. Further, the scoring methodology needs to be understood by a specialist and aligned with the corporate risk matrix used by asset managers. This paper describes how software systems can be leveraged to provide effective communication in the organisations "language of risk" and helps to visualise the accumulation of risk from wells that are aligned with the corporate matrix. This small step change vastly improves the understanding and communication of well integrity risk throughout the organisation enabling installation management early challenge, better resource utilisation and the monitoring of creeping accumulative change.

This paper introduces Dynamic Risk Modeling and reports on a 2016 proof-of-concept demonstration of the emergent capability. While Dynamic Risk modeling can apply in any high risk environment, the demonstration focuses on the High Pressure, High Temperature (HPHT) drilling environment and uses 2010 Macondo cumulative risk as a demonstration scenario. Dynamic Risk Modeling integrates the effect of human decisions with technical conditions; it enables three evolutionary capabilities in risk management: The awareness of cumulative and current risk based on input from multiple points and times of originThe quantitative insight of the coupling effect of multiple hazards when barriers or controls change conditions or failThe incorporation of real-time data into risk awareness, management and decisions The paper demonstrates enhancement of the digital oilfield by applying real-time data to predictive decision making. The model receives continuous well data, processes it through the model with other environmental and human factors, and translates it into real-time risk awareness and insight. The demonstration of Dynamic Risk Modeling is applied to the Deepwater Horizon drilling environment in April, 2010 to show how a real-time representation of current and cumulative risk could have aided decision makers with critical information and insight.

Energy companies recognize that they have become high-value targets and that their operations can be disrupted using only cyber means. Supervisory Control and Data Acquisition (SCADA) systems, Distributed Control Systems (DCS), and Process Control Systems (PCS) are of specific interest to attackers as these operate critical infrastructure. Risk management is extremely difficult because every risk has a high cost attached and there are no reliable statistics to assess the likelihood of a risk occurring. The challenge is to understand an organization's risk profile and tailor its risk management strategy accordingly. Industrial networks facilitate the free flow of messages that can allow poison packets to transmit with potentially disastrous effect. For instance, Distributed Network Protocol (DNP3) Secure Authentication does not protect against implementation failures in the device that can be exploited through malformed packets, therefore making protocol-aware validation and restrictions essential. A comprehensive approach to restricting what can and does occur within an industrial control network will help effectively mitigate the systemic risks that are inherent within the industrial control environment. To comprehensively protect the critical infrastructure that powers civilian businesses and homes, the intelligent approach demands a secure-system design that controls and monitors all entities within the control system from users to vulnerability-prone endpoints and protocols. Not all attacks occur from external sources and so boundary protections such as data-diodes and firewalls are not enough. Such solutions, however, also must preserve operational efficiency to assure that the cure is not worse than the malware, in relation to operational efficiency. Successful risk management requires an effective assessment of the inherent risks and the most viable mitigation strategies for those risks. This paper outlines these systemic industrial control specific cyber-related risks, and offers an approach for intelligently monitoring and controlling cyber activity to reduce a cyber-related impact. This approach promotes systems-based methods that focus on architectures that leave critical operations uninterrupted.

The Operator has long recognized the risks associated with specialist well engineering and wells services software and how insufficient management could have consequences to both safety and the environment. Sawaryn et al. (2003) laid out a set of principles for improving the management and use of Safety-Critical drilling engineering and well services software. Through a series of initiatives, the Operator has developed these principles into a risk based management practice aligned to international standards; IEC 61508 (2010). This has enabled better understanding by global wells and IT on the influence software systems have on group loss of well control risk barriers. It has also enabled the creation of a more robust management framework. A significant development has been to simplify the classification and differentiation between Safety-Critical and Safety-Related systems. It was recognized that applying a broad brush definition of "Safety-Critical" to wells applications created a high burden of responsibility and weakened the definition of Safety-Criticality. For example a system with no human interaction before an action occurs should be managed more rigorously than one whose output can be validated and corroborated. When applying these criteria to wells software it was found that none were Safety-Critical, therefore the scope of this paper is confined to Safety-Related software. A risk based approach has been used to enable easier classification of software, removing some of the ambiguity prevalent in the past. This has reduced the risk for project delivery and IT support operations. Using risk based approach has also allowed a more objective approach to management, enabling better measurement for the controls discussed in this paper. Work in this area is still relatively immature and there remain many challenges. For example, data integrity can be difficult to manage and can weaken controls such as algorithm validation. Additionally complex systems used by wells but owned by other upstream functions can be difficult to manage unless those functions follow the same methodology. This paper outlines the initiatives the Operator has taken to reduce the risk presented by Safety-Related software, highlighting the benefits, challenges and opportunities.

The time spent on drilling operations in the development of a field is a major percentage of the costs involved in the production of hydrocarbons. However, one of the major challenges facing drilling and re-entry operations today is the prevention of costs and schedule overruns. This is because of the nature of drilling and re-entry operations, the risks involved with the different tasks from well conception up to the completion is not properly accounted for. Other factors like the failure of a new technology planned to be deployed, the pressure of time and the increasing regulatory of safety and environment requirements have made it difficult achieving the financial and timing targets set. The shortfalls in well cost estimation and control are due to reliance on outdated or poor methodologies. Generally, drilling AFE's (Authorization for Expenditure) are generated by applying deterministic methods to offset data and, which primarily consists of the recorded and documented experience of the drilling operations. From the analysis of these data, estimates for drilling performance and the likelihood of facing drilling complications are estimated. Added to all these are also an element of expert judgment, though subjective, that is drawn upon in the estimation of time and costs for the new well/s to be drilled or re-entered. These estimates suffer from the lack of a true scientific approach to predict time and costs which becomes apparent immediately there is a deviation from the planned operations. There has been limited published work involving the applications of probabilistic methods in drilling engineering, particularly when estimating times and costs for re-entry and drilling operations. This fact is even more acute when considering the evaluation of re-entry opportunities and new drilling technologies. There is little or no scope to incorporate an estimation of risks and non-productive time (NPT) in a meaningful manner. This paper presents an accurate probabilistic and risk analysis approach using a subsea re-entry well as a case study. An intervention operation was planned and this method was used to accurately predict the amount of days (and cost) required for the operation, factoring in all the possible risks and time impact on the operation. A deviation of less than 5% was observed when the actual expended time and cost was compared to the planned.

A number of SCSSV failures led to deferred production, loss of integrity and additional costs resulting from interventions to restore integrity. An investigation team initially focused on hardware components, until a new multidisciplinary team applied systems thinking to expand the investigation to include operations, subsea controls and fluid components, where analysis on system fluids revealed the root cause – through a series of tests – to be fluid and material incompatibility in the subsea tree hydraulic circuit. Further analysis provided the development of a failure mechanism and understanding of how the problem was exasperated. By executing an integrated investigation, the team gained valuable insight on the fluid and material interactions of the system and was able to make vital recommendations to restore production as well as implement mitigating factors in the approach to completions and well integrity. This paper highlights the collaborative approach to resolving well and subsea integrity between the production, wells and subsea disciplines.

As Oil fields containing stacked reservoirs are developed, it is not uncommon for these reservoirs to be in pressure communication. The extent of pressure depletion may determine the viability of potential new drills. Possible communication of the X1 reservoir with the Y1 reservoir was initially suspected when a Material Balance study earlier conducted on the X1 reservoir did not yield a reliable historical pressure match using mapped volumes of the X1 thereby suggesting potentially larger Oil in Place number in the X1 reservoir. Also, the structural overlay of the X1 over the Y1 reservoir having compatible hydrocarbon contacts seemed to also indicate possible communication between the X1 and Y1 reservoirs. The conclusion of the Material Balance study recommended a more detailed probe into the X1 reservoir to ascertain the impact of communication on the reservoir development strategy. A simulation study was conducted primarily to evaluate the impact of communication uncertainty on the new drill recovery. Three scenarios were considered namely: Communication of the Y1 with the X1 through the aquifer; Communication of the Y1 with the X1 through the hydrocarbon and the Y1 completely isolated from the X1. The history match indicates reservoir communication through the aquifer as the most plausible scenario. However, due to active reservoir drive mechanism of gas Cap expansion and strong aquifer support in the X1 reservoir and possibly same in the Y1, all three scenarios did not adversely affect the potential recovery in this instance with recoveries between 50-59%. Hence incorporating surveillance information from offset producers is vital in evaluating production potential of zones which may be unproduced but not virgin.

The concept of sustainability implies concern for the present and future generations. In its true form, sustainability requires striking a good balance in the decision-making process by considering the economic, environmental and social aspects of any development, including the development and maturation of oil and gas projects. Based on current projections of global population growth, there is no doubt that future demand for energy will increase significantly from current levels. On the other hand, the envisaged population growth and increased demand for energy will present opportunities and responsibilities for oil and gas companies. This will be compounded by the fact that the additional oil and gas volumes are more likely to be derived from locations with very complex economic, environmental and social characteristics. As such, the ability of oil and gas companies to sustainably mature the opportunities, and effectively manage the responsibilities, will have significant implications for energy security and stability at various levels. This paper discusses the role and significance of non-technical risks (NTR) management as a sustainable development framework, and the need for proactive NTR integration and management in oil and gas project maturation and development process. Efficient and effective management of NTRs has the potential to contribute to greater transparency in the oil and gas business, better returns on investments, and sustainable energy security and stability.

The amount of information available for field development planning is limited, forcing the Production Strategy to be designed under great amounts of uncertainty. During its implementation, new information allows the adaptation of the strategy for economic gain. This work reproduces the field development process under geological uncertainty in case study UNISIM-I-D (benchmark case based on Namorado Field in Brazil). The main objectives are to evaluate the process and observe the evolution of risk curves, all in a controlled environment with real field features. The methodology generates new geostatistical images based on new well logs, assimilates production data using an ensemble-based method and re-optimizes the production strategy using a hybrid algorithm. The field development is carried out by repeatedly applying this framework under human supervision. Each step is customized using algorithms to simplify the implementation and to reduce computational effort, making this methodology more appealing for practical use. New data are collected from a high-resolution reference model that does not belong to the ensemble of models. The process starts with a production strategy, previously optimized under the uncertainties of the case study, which yields the real economic outcome within the original uncertain range. Results show high quality history matching that excessively reduced the risk range and the variability of the updated model sets. Optimizations on the production strategy, based on the updated ensembles, consistently increased the expected monetary value of the project without guaranteeing an increment in the real NPV. Applying the methodology repeatedly throughout the field development increased the EMV by 29% (from 1.532 to 1.975 billion USD) while the real NPV decreased 2% (from 1.346 to 1.319 billion USD), falling out of the expected range and revealing that the model sets did not fully represent the real field. The lack of good representation is aggravated by heterogeneities inherent to the unknown reservoir, which are difficult to identify using only well logs and production data. The results from the application of a closed-loop reservoir development process in a controlled environment warn against similar hidden mechanisms happening on a real field development under similar circumstances. They reveal intrinsic pitfalls in reservoir modeling that may contribute to production forecast problems and call for a reflection on how reservoir uncertainty assessment is performed. We prove that large sets of models do not guarantee coverage of geologic uncertainties as the field development process naturally changes the risk curves.

The relentless exploitation of hydrocarbon resources to meet ever increasing demand has compelled upstream companies to focus on deep and ultra-deepwater. Flow assurance is one of the most critical aspects in field development. The hydrocarbon product needs to be transported from a remote well to the process facility, without experiencing significant energy losses to the environment. Some of the oil discoveries in Indian deepwater are having high wax content; high Wax Appearance Temperature (WAT) and pour point flow assurance is a major challenge in low ambient temperatures. A number of solutions like chemical injection (CI), mechanical insulation (Vacuum Insulated Tubing (VIT), Pipe-in-Pipe (PIP) etc.), Pigging, Piggy back line (PBL) and Electrical heating of flowline (EHFL) are the available means of mitigation to address these flow assurance challenges. In addition to high ‘steady state’ thermal insulation performance, the system has to provide good transient cool down behavior to prevent wax or hydrate formation during shut down and to minimize the time required for start-up. Through this paper an attempt has been made to generate a matrix for identifying the likely option for the means of mitigation individually or in combination, both for steady state and transient scenarios. The various options have been studied for suitability for flowline under different flow scenarios like steady state, shutdown, restart, and turndown and for redundancy. Emerging options are further technically analyzed qualitatively, based on the extent of field use, robustness, tangible & intangible benefits etc. and evaluated to arrive at a suitable flow assurance strategy. For field X located in 600–700 meters of water depth, the combination of PIP and CI with EHFL as a fall back is emerging as the most suitable option. During initial start-up, the flowline can be preheated using electrical heating and the sample taken for identification of suitable inhibitors and for arriving at the required dosage. During shutdown and restart scenarios electrical heating of flowlines can be adopted to prevent the fluid from gelling. The solution matrix presented in this paper will help in evaluating the available options and to arrive at the best suitable flow assurance strategy and means of mitigation, to any field during all operating scenarios.

Electro-hydraulic robotic tools that perform well interventions on electric line (e-line) have come of age over the past 10 years and can now be used to accomplish tasks previously done with the use of jointed pipes and/or coiled tubing conveyance system. Examples of such tasks are downhole milling, shifting of stimulation sleeves, etc. Surface real time monitoring and control features are required to ensure that such tasks done by robotic tools are successfully achieved with high accuracies. As the demand increases to use this type of powered devices in a more hostile well environment, service companies have developed technologies to expand their operating range. Starting from late 2013, the robotic technology solution has been used in KPO horizontal sour wells to close stimulation sleeves when required for reservoir fluid management, to convey perforation guns, to convey production logging tools and to mill frac balls and ball seats. This paper will present four case histories of the robotic technology application in the Karachaganak field. It will discuss the advantages of the technologies, the challenges and the future improvement required to further optimize the field operations.

This paper is a case study of a well intervention performed by PETRONAS Carigali Sdn Bhd (PCSB) in Sarawak region to investigate and rectify a breach in well integrity. The review and discussion demonstrate that the intervention not only ensured compliance with existing well bore risk management guidelines but also reduced operational rig cost and enabled increase in production. The paper identifies the aspects of what appears on first view to be a straightforward well integrity diagnostic process, but which on deeper evaluation exposes the wider and acute impact of the outcomes of such a diagnosis. The nature of the diagnostic technique is examined, and the interrelated impact on PCSB HSE requirements, platform operating efficiency, and field-wide production. The well intervention and the subsequent targeted rectification made possible by the precise nature of the diagnosis, enabled PCSB to bring this well back online and restore its gas production. This gas production is vital for several of the gas lifted wells in the field. Restoration enabled PCSB to increase field production significantly. The study concludes that accurate, reliable and rapid integrity diagnostics should not be evaluated as only relevant as a means of HSE management but also a means of cost management and in sustaining or increasing overall production.

This paper portrays how drilling project costs can be reduced significantly, through the use of Risk Impact Amalysis, which is vital in the current era of unprecedently low oil prices which puts pressure on the whole chain of oil and gas services. New ways of thinking and inventiveness are required if we are to keep drilling as opposed to stacking rigs which is happening at an alarming rate particularly on land in the U.S.A. If the cost of drilling cannot be reduced further, rigs will be stacked, several "cold" and the lucky ones "warm’. This paper desrbibes how, through focused risk anaylsis, a 10,000 rated rig was allowed by the authoriesto drill as opposed to the more normally required 15,000 psi requirement.

With the production declining trends and dwindling reserves for a 35-year-old Samarang offshore field, Samarang Redevelopment Project was kicked-off with a vision to implement Integrated Operations (IO) as Asset Management Decision Support tool. To realize the expected reserves and optimize the production, an "Integrated Asset Model" (IAM) concept is introduced with a state of the art modeling techniques to treat the asset as a whole unit rather than isolated silos as was being done traditionally. Understanding the complex interactions and synergies between reservoirs, production networks and process facilities was the key in the decision making process, where strategies implemented and decisions taken on the production networks would greatly impact the reservoirs' performance and vice versa. This was achieved by creating an Integrated Asset Model that included the eight reservoir simulation models, together with a common production network model of around 80 strings and a complex process facilities model. This new business process is supported by an underlying system that keeps model up-to-date with the current reservoir and production changes. This innovative approach for long term production planning is used to better manage and plan the continuous production flow stream from reservoir to field export point. The main objectives for the Long Term Production Planning approach are:Obtain more accurate and reliable forecasts by having the reservoir, surface network and process models integrated.Recognize the complex interactions between reservoir and production networks and understand facilities constraints and potential bottlenecks.Compare different EOR, redevelopment strategies scenarios thereby obtaining the optimal scenario.Increase collaboration and reduce communication time between different domains to enhance the decision making process from an integrated asset management perspective. This approach has been implemented recently for the Samarang long term asset management strategy and has revealed very remarkable results which would help the asset team for improvising the short and long term strategies. The paper also divulge how the underlying foundation platform has been set-up to run such integrated studies followed by capabilities to run the various optimization scenarios to assist the development strategies especially after introduction on enhanced oil recovery (EOR). This innovative approach delivers value with the enhanced asset management by focusing on decisions to improve production and operations performance. Forecast production profiles reported from the subsurface models now incorporates the impact of network and process facilities, which allows for more efficient decisions leading to maximization of the production and reduction of CAPEX/OPEX costs. Some of the key benefits and early value gains of an Integrated Asset Model for Long Term Production Planning (LTP) are:Realized the promised reserves expected by the EOR program by optimizing the production.Cross-domain collaboration among the different disciplines as Reservoir Engineers, Production Technologist, and Process Engineers are working together. In other words, it brings people, process and technology together. This promotes effective decision making.

This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier. During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value. The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design. Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal. Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas. The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project. Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.

This paper will explore best practices for operators to make risk mitigation arising from process safety management (PSM) systems an integral part of efficient and effective operations. Operational risk arises from a complicated set of interrelated parameters and is viewed and managed in differing ways depending on the role and level in the organisation. The challenge is to simplify this complexity enabling all levels of the organisation to collectively focus on the major elements of risk that are important. Conceptual models like James T. Reason's Swiss Cheese barrier model or Bow-Tie models have been developed in an attempt to describe the inter-related nature of operational risk, but the industry has yet to develop operational systems that enable routine management of operational risk. Regulators are requiring companies with hazardous installations to implement process safety management systems. This has led to functionally focused management and process safety systems primarily aimed at compliance. Across the globe there are a number of process safety management models, from the Occupational Safety and Health Assocation (OHSA), California's Division of Occupational Safety and Health (Cal-OHSA), Safety and Environmental Management Systems (SEMS), UK Health and Safety Executive (HSE), the Energy Institute, and even the Tier 1-4 leading and lagging indicators from the American Petroleum Insititute (API). Furthermore, each company has established their individual process safety management or control systems to comply with or operationalise these models. Common to most systems is the concept of barriers, lines of defence, or layers of protection as a means of understanding how to protect operations from major accident hazards (MAHs). The challenge every organisation faces is how to relate the performance of their process safety systems in a meaningful way to the operatonal reality of the plant. Too often process safety leading indicators end up being focused on programme health and do not provide a forward looking view of how all the operational risk comes together where it matters most; frontline operations. To be successful in creating a sustainable business in hazardous industries, organisations need to collectively manage risk across their operations in a routine and efficient way. This requires a change in the dynamic between safety and productivity, where safety is not set against production and risk mitigation becomes an integral part of efficient and effective operations. Organisations need a holistic and common means of balancing risk against production at all levels of the operation. This paper will review existing PSM models, the challenge in relating PSM performance to the operational reality of the plant and how a new breakthrough provides a simple, elegant means of relating the collective performance of a company's process safety systems to the real cumulative risk impact on plant operations at any given point in time. This breakthrough is not a new process safety model nor an addition to existing process safety models. It provides the means to connect deviations from process safety performance standards to the operational reality of the plant through a common language of risk so that operational risk mitigation can become an integral way of achieving efficient and effective operations. By doing so it allows operators to understand their levels of MAH risk in a prominent and real time manner. MAH pathways through the fundamental barriers can be identified by combining the residual risk arising from deviations in any process safety systems. This provides a key indicator of MAH risk. This new breakthrough will allow people at all levels in an organisation to better understand the cumulative operational risk they are carrying at any given time which can be used to improve operational decision making. The benefits it delivers range from serving as an early warning system for potential MAH related incidents (allowing organisations to make proactive interventions), better prioritisation of maintenance to more informed decision making around risk and activity at the daily operations level.

Gangway equipped: offshore support vessels, intervention vessels, construction vessels, and other mono-hull vessels, capable of providing gangway access to offshore facilities in exposed sea areas has great potential. It is playing an evolving important role in making new marginal yield field development economical, reducing exposure to risk, and extending the life of the existing oil and gas infrastructure. Otherwise known as Walk to Work (W2W), this marine manning approach for offshore facilities can be used on a regular, fixed term, ad-hoc or exceptional circumstance basis. It is capable of providing significant benefits over existing provisions including: improved safety, increased workforce productivity, greater manning flexibility, and reduced lifecycle costs. The W2W vessel can range from relatively small, fast workboats, to large semi-submersible ‘flotels’ stationed alongside fixed platforms. Within this range, it is the mono-hull vessel where there is the greatest opportunity for the oil and gas industry to realise significant (currently unexploited) gain. Depending on the capability of the chosen vessel, a W2W solution may offer: gangway transfers, hotel, hospital, helicopter, rescue and recovery, subsea and splash zone inspection, cargo, crane, fabrication and other facilities. Offshore facility operators looking to improve performance by use of W2W; firstly need to fully understand their requirements; secondly, be open minded and innovative when looking for solutions; and thirdly, realise that to fully exploit W2W there are many aspects that need consideration to strike an optimal balanced solution. This paper presents the potential significant opportunities offered by W2W, and discusses the main areas that require consideration during the requirement definition and subsequent development of a W2W solution. The paper references a recently released guidance document covering W2W which was developed within a joint industry project with fifteen industrial partners (DNV GL W2W JIP 2015).

Following the Macondo incident in 2010, industry has taken steps to improve response readiness in case of a subsea well control incident. This led to Oil Spill Response Limited's (OSRL) Subsea Well Intervention Service (SWIS) being formed. SWIS allows industry the capability to better respond to a subsea well-control incident by providing state of the art subsea well intervention equipment. This paper will provide an overview of SWIS and demonstrate how the equipment is stored and maintained in a response ready state, including information on periodic maintenance performed and logistics philosophy for mobilisation. In addition, it will provide an update on the Containment Toolkit, allowing for cap and flow operations. The equipment available includes 10K and 15K psi Capping Stack Systems (CSS) and Subsea Incident Response Toolkit (SIRT); comprised of Site survey, Debris Clearance, Subsea Dispersant and Blowout Preventer (BOP) Intervention System. The equipment is stored at strategic global locations, covering the main areas of oil exploration and production worldwide. It is transportable by land, air and sea and can be called upon by any OSRL SWIS Capping member. Further to this, the OSPRAG Capping Device will be discussed, which provides cover for the UK Continental Shelf. To enhance the capability of SWIS the Containment Toolkit will be delivered to OSRL during 2015. The equipment in the containment toolkit is designed to supplement standard industry well test hardware to create a containment system. It comprises long-lead equipment not readily available in the current industry and minimises response times by allowing a responding well operator to draw on existing resources.

This paper examines the increasingly significant issue of obsolescence and its prevalence in the light of extended life operations in the offshore oil and gas industry. Obsolescence can be likened to an insidious creeping plaque; it hides in the wake of new and changing technologies to take everyone by surprise around 10 years into the system life cycle. To mitigate this problem a robust system of obsolescence management is necessary. This view is endorsed by the Health and Safety Executive (HSE), which recommended last year that the energy industry develops a corporate culture that embeds an ageing life extension (ALE) philosophy into asset integrity management for the long-term future (Health and Safety Executive, 2014). An important part of this process is the establishment of comprehensive procedures, systems and recording that allow for continuous monitoring of assets plus anticipation of issues, so that these can be managed proactively. A progressive approach to obsolescence assessment involves offshore site surveys, reporting and detailed design studies. The resultant inventory is then subject to further assessment, using established methodologies and weighting factors to determine vulnerability, impact and risk. Sophisticated database systems now available for the recording, storage and analysis of such “intelligent” inventories. These allow operators to gain a clear and realistic picture of their assets, their associated systems and their place in the lifecycle. Such databases also provide a platform to explore tactics and strategies for removing or mitigating any obsolescence risk. Nervousness within the industry about the impact on everyday activities is largely unjustified: both obsolescence assessments and system migrations can be carried out with minimal intrusion on normal day to day operations. Today's innovative migration upgrades cause near zero disruption to field wiring. Furthermore, when the value of such exercises is considered in terms of accident prevention and safeguarding against future costly disruptions, there can be no question as to the validity of such investments. With many assets remaining in production for over 25 years, their associated control and automation systems continue to be used well beyond their life expectancy. Technology marches on, process functionality changes, the availability of spare parts declines, and eventually manufacturers and third parties are unable to provide technical support. Collectively, these issues pose major risks to production, safety and the environment.

This paper describes the key elements of managing uncertainty to deliver sustainable unmanned operations: developing timely and appropriate operational philosophies; focusing on designing hazards out, in the very early phases of a project; and the importance of key business drivers. The early establishment of operational philosophies contributes significantly to project certainty and would be considered mandatory to deliver on a not normally manned concept. These philosophies are fundamental in terms of reducing cumulative risk to the individual, high production availability and facilitating optimal life cycle costs. The influence, importance and implementation of drivers, such as Inherent Safety (IS) and Operational Efficiency (OE), in order to manage uncertainties across project phases are discussed. Demonstration of As Low As Reasonably Practical (ALARP) risk can be subjective if these drivers are not included in the early design phases. The paper also shows that inherently safer design and sustainability are lifetime partners. The operations philosophy is a key element in defining to the project, how the “customer” wants to run the facility. It is essential that the operational philosophy should not be derived from the output of the concept design i.e. “after the event”. Rather, the operations philosophy should be a parent document which should drive some of the concept requirements. Omissions from or lack of attention to the operations philosophy, in any phase, will inevitably cause increased risk, loss of efficiency, lost production, unnecessary work for both vendor and customer alike and potentially lead to not achieving unmanned status. The influence of project drivers in each project phase needs to be understood and acted on for certainty of outcome and the delivery of not normally manned or minimum manning concepts. The paper concludes that organic growth of complexity causes loss of value on all projects and it is essential that the operational philosophy is established in the concept phase to reduce complexity and certainty of outcome.

Pressure build up between cemented casings — in drilling and production wells — has been a major challenge all around the world. The cause, in most cases, is a poor cement job that allows fluids to migrate through micro channels from the formation all the way to the surface. This problem has been solved by pumping or squeezing a polymeric based resin — with major bonding properties — that can be accurately designed for a specific setting or curing time, based on the application temperature. This resin is pumped through annular injection ports in the well head. Due to the resin's particle free characteristic, there is no restriction or plugging risk while pumping. Once the resin is pumped down the annuli into the micro channels, it will set or cure and isolate the pressure build up from the source, providing a safe working environment at the surface. Thermal activated resin is a new technology that has overcome a lot of traditional cementing problems. The resin acts as a fluid and can be designed on a wide range of weights and viscosities, and it can also be adjusted to react at a specific formation or ambient temperature. This paper presents case histories on field applications and lab tests to support the efficiency and liability of solving Casing- Casing Annulus pressure build-up scenarios in the Middle East.

Although the importance of human failures in causing accidents is well known in the Oil & Gas industry, historically the focus in safety cases or site safety reports has been less on human failures than on technical failures in major accident hazards (MAH). In order to address this disparity the Company has developed a process to manage the risk of human error across their assets. This is primarily for mature tasks and activities that is things that are currently done and have been for some time, as well as new tasks and activities from projects and modifications. This involves developing a robust process to select specific activities where Major Accident Hazard (MAH) scenarios had been identified from the various safety studies. Progress at first has been slow but by developing sound foundations the company has started to show significant benefits in managing human failures that may lead to MAH scenarios. This paper describes and details how this process has gained momentum by the Company providing dedicated resources to support the assessment process and to facilitate updates to site procedures. This work involves both operators and maintenance technicians in the analysis and site walk- and-talk through of the task. The process has identified safety related risks that were not previously recognised and significant environmental risks, operational risks (equipment damage, process upsets) and potential downtime of plant. A key benefit of employee involvement is that employees are actively involved in human error analysis in their day-to-day activities and recognise where human error is critical as well as the true value of maintaining key recovery systems Key learning points and case studies are described in order that they can be used by other organisations to assist in any application of the process. This process is very much work in progress. However, foundations have been developed to ensure lessons are learned and to ensure a standard approach to using a human factors approach to manageging MAH across the organisation.

The UK Oil & Gas (O&G) faces significant challenges to ensure future economic potential is maximized. Current issues include escalating maintenance backlogs, facility unreliability; an inability to liquidate production-enhancing or important asset integrity workscopes and uncertainty of the rationale justifying existing maintenance programs. This paper presents the application of a novel maintenance optimization technology that has delivered performance improvement through the deterministic consideration of both commercial and reliability criteria when determining planned maintenance intervals. Real case studies are presented alongside the concomitant benefits. The technology was used to determine an optimized planned maintenance program for deployment in both existing operations and new facilities, and has delivered benefits when compared with traditional approaches to determining maintenance intervals. The technology marries both technical and commercial considerations when determining optimized planned maintenance and, in this way, the modulation of planned maintenance programs in response to changes in production, commodity value or equipment reliability is easily achieved. Based on results of the work carried out using the technology, it is proposed that there are significant benefits available to the UKCS through the adoption of similar techniques, as it is understood that many operators currently struggle to justify existing planned maintenance regimes, and to demonstrate a defensible means by which to alter these regimes in response to a changing economic and reliability criteria. Application of this new technology may provide a means of modulating maintenance in response to changing criteria and offer potential concomitant benefits in helping tackle backlog, bed space and production efficiency challenges.

This paper presents a resilient approach to designing production facilities and processes based on the capability of organizations to effectively innovate and adapt to changes and risk while maintaining quality and profitability. It presents a practical and innovative method that uses benchmarking to show how to identify risk factors and develop prioritized contingency plans for marine facilities, based on risk and criticality of operational weaknesses. The investigation is descriptive and research-based, combining field research with bibliometric case studies. The research illustrates the relationship between variables, and an oil industry case study provides the context for the research. The process used includes assessing risk, characterizing effects, evaluating resilience capacity, and designing solutions. Risk assessment is developed for operational, process, supply chain, and other risks, whereas the capacity for resilience is assessed on the basis of capabilities to monitor the environment, incorporate process flexibility, and adapt organizationally to change. In addition, the bibliometric analyses of companies in the energy sector were conducted to identify and document best practices and lessons learned. On the basis of this investigation, a strategic framework for facilities development was formulated that incorporates excellence in operations, innovation, and efficiency. This process optimizes the management of resilient facilities based on the implementation of an integrated cycle, including a proactive business and corporate culture. It includes assessing risk, evaluating response capability, designing the balance between reactive and proactive capabilities, planning resilience, and managing the implementation of the facilities planning strategy. The paper underscores the importance of integrating and improving business processes and tools to facilitate decision making in a timely and reliable manner while managing risk and operational and environmental uncertainties. Consequently, in addition to focusing on the causes of changes and risks, resilience is oriented toward enabling adaptation to changes during the project lifecycle in the face of the unknown. Usually, companies have a tendency to dedicate their resources to the area of highest vulnerability (high occurrence and high impact) and to neglect the areas of medium vulnerability that result from low impact but high frequency events. The medium impact method identifies these risks; it also defines factors that contribute to designing resilient facilities, creating competitive advantage, managing internal and external adversities, and incorporating lessons learned from other projects. Growing uncertainty within various business areas has attracted the attention of many companies, particularly within the oil and gas industry, in which many risk factors in exploration, drilling, production, and marketing are managed onsite. This paper summarizes best practices and lessons learned from benchmarking cases of resilient organizations that have integrated risk management methods for uncertainty and achieved high value innovations within their processes and products. These companies have attained excellence in operations while effectively innovating.

This paper reports on the benefits of applying Fuzzy Logic Control (FLC) over the traditional Proportional-Integral-Derivative (PID) approach to improve the operation reliability of plant of produced water treatment. Reservoir rocks normally contain both petroleum hydrocarbons and water. This water is frequently referred to as “connate water” or “formation water” and becomes produced water when the reservoir is produced and the fluids are brought to the surface Produced water is the largest volume waste stream in the oil and gas exploration and production processes. Fluid produced in the Colombian Rubiales and Quifa oil field is composed by approximately 95% of water and 5% of oil. Separation of water from production fluid and its treatment and disposal are critical for the continuous of oil production. Applying Fuzzy logic as automatic control approach for the facilities that separates the water and treats it has represented a 10% increase in the amount of water treated using the same installed infrastructure. This improvement represents savings in CAPEX of US $ 5.76 per barrel of water that is treated with the previously installed infrastructure. OPEX savings are significant and are related to operating costs that are avoided because (1) by not having to build additional plants to treat water that is processed with the current infrastructure no costs associated with its operation (2) due to the better functioning of treatment plants chemical consumption is reduced and (3) the automation improvement allows much better use of staff assigned to the facilities. The benefits in operation of the plants associated with fuzzy logic control were achieved (1) on having maintained producing(operating) in more continuous form the water treatment plants, (2) Decreasing the shutdown of the facilities by reducing the variability of the process variables, and (3) by increasing the level of automation of the plants and the reliability in operation. Application of intelligent control approach is a novelty in the industry of oil fields. The main control approach applied has been Proportional, Integral and Derivative (PID) approach.

Problem Statement: A hazard identification and risk assessment analysis are ones of the most important elements of an effective health and safety management system. Different standard specifications for management systems (including BS OHSAS 18001:2007, ANSI/AIHA Z10-2010, ISO 14001, BSEE SEMS, CORE Safety and others) require hazard and risk assessment to be performed on a regular basis. However, it has been observed that these traditional approaches do not necessarily facilitate appropriate prioritization of risks to manage and control adverse injuries and illnesses in the workplace. Considering the importance of developing effective approaches to hazard identification and risk characterization, potential ways for enhancing typical hazard and risk assessment procedures, involving numerous aspects of the safety culture paradigm, were investigated. Specifically, it was decided to develop a methodology of hazard and risk assessment that would be applicable to a specific industry (for example, petroleum industry), with testing first performed in a controlled environment. Objectives and Scope of the Study: The objective of the article is to analyze a current hazard and risk assessment process in a medium-sized consulting firm, complaint and certified in accordance with OHSAS 18001 specifications, and to describe a methodological basis for continued improvement. Because traditionally occupational health and safety management systems use two-dimensional (likelihood (L)/severity (C)) risk assessment approach, an enhanced methodology was referred as the three-dimensional hazard and risk assessment method. Method: Hazard identification and risk assessments were performed for all routine activities. After the hazards were identified for each working group, the hazard list was distributed to all members of the working groups and they were asked to rank their Perception (P) of how the hazards were being addressed by the company and to also rank how important it was for the company to address the hazards (Importance - I). Based on the analysis performed, new metrics for risk level were introduced, based on different combinations of observed parameters. For each new metric, a scale of risk levels was proposed, utilizing the Monte-Carlo simulation approach, with Crystal Ball software applied. The 25th, 50th and 75th percentiles of all possible values of risk level were chosen as ranking criteria. Results and Observations: Importance (I) and Perception (P) introduced valuable information for hazard identification and risk assessment. New risk metric LCI/P was proposed instead on LC. Three-dimensional model of “risk profile” was proposed for implementation, to reflect various aspects of effectiveness of the management system. Conclusions: Risk perception and employee's vision of importance of hazards should be considered as a significant element of an enhanced risk assessment procedure. Applications: The proposed methodology can be used by oil and gas facilities’ managers to increase effectiveness and return on investments for their health and safety activities. Innovations or Technical Contributions: New methodology of hazard and risk identification was proposed.

Well integrity management (WIM) is predominantly viewed from a perspective in which technical, mechanical, and operational solutions are applied to help reduce the risk of uncontrolled release of wellbore fluids at unwanted times throughout the life of a well. Wellhead integrity, completion integrity, and zonal isolation are a few of the key performance indicator (KPI) parameters considered. This paper discusses WIM from a drilling fluid management perspective. Drilling fluid loss (lost circulation), if not properly addressed at the correct time, can lead to significant well control issues. Particulate lost circulation materials (LCMs) have been in use to manage lost circulation for many years. This paper discusses preventive (proactive) and remedial (reactive) operational strategies to deal with such issues. Preventive strategies are employed to help reduce the potential for lost circulation. This strategy involves the initial consideration of lost circulation management from the wellbore planning/design phase. Improved drilling practices can be emphasized and planned by examining drilling fluid hydraulics and all other fluid engineering aspects. Finally, effective preventive engineered solutions can be considered and made available to manage losses well before they are encountered. Conversely, a prudent engineer will have remedial strategies in place if the preventive plan does not work. This strategy also includes loss contingency plans to be in place if unexpected loss events occur. Examples are discussed with respect to how previous knowledge and lessons learned can play a critical role in developing contingency plans to effectively manage losses when they occur. In summary, this paper discusses WIM from a drilling fluids perspective and, more specifically, through managing drilling fluid losses. The preventive and remedial operational strategies presented can be critical in managing drilling fluid losses and helping prevent wellbore stability or well control situations.

Like most companies today, Premier Oil (Premier) have been developing a Well Integrity Management System (WIMS) in order to provide a broader insight into both surface and subsurface well integrity issues. In addition to evolving their WIMS policies and procedures, Premier also chose to implement an effective and integrated well integrity data management software system to improve safety and operational efficiencies in the field, to increase production through reduction of well shut-in times, and to create a positive and proactive culture of managing well integrity which would allow Premier to proactively monitor and manage well integrity issues. This paper focuses on the reasons for implementing a well integrity management software system, the benefits to Premier by implementing the system, and how the system is used across all of Premier's assets. Premier started by collecting and collating data to understand whether or not a well was operating within its safe operating limits, this included information from other applications to fully understand the well integrity picture. From that, a database of the wells was set up, wellhead templates created, test types and data input forms generated, and incorporation of Premier's WIMS policies and procedures into the application. During the first year of implementation, the goal was to create a baseline of well integrity statuses for the current well stock and to establish workflows to manage the well integrity issues more effectively. The overall number of wells Premier operates is growing significantly with new and future developments, and hence this baseline establishment of good well integrity practices is preparing the company for future challenges and potential production concerns if well integrity issues arise. Additionally, there were qualitative objectives: – Improvement in the monitoring and managing integrity issues proactively; – Increased visibility of well integrity management within and outside the company; – Ease of accessing all of the well integrity information and analyzing that data to find and fix problems; – Improvement to data accuracy and availability to increase productivity by having up-to-date knowledge of well integrity issues. To-date, Premier has already seen an improvement in understanding well integrity issues across all their assets. Prior to implementation of the new software, data was stored on spreadsheets with only key personnel involved and understanding integrity issues. Now a more informed group recieve quick notification when wells are operating outside their agreed parameters, which has led to an overall improvement in proactively managing well integrity issues. Additionally, Premier also expects a more stringent regulatory environment in the future, at which time the existing spreadsheet-based system would no longer be workable or acceptable to external authorities.

The NORSOK D-010 standard established a definition of Well Integrity: “The application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids and well fluids throughout the life cycle of a well.” If that is the ultimate goal, how do we get there? This document was created with the goal to provide references, a basis of information, and guidance for best practices to operators for developing and implementing a Well Integrity Management System (WIMS). This paper will review the industry documents that address Well Integrity and outline their requirements or recommendations of a Well Integrity Management System (WIMS). This paper will address what elements should be covered in a WIMS. It will also expand on each of these elements in order to provide information and guidance for an operator to build a WIMS. This paper will cover the topic of best practices for successful implementation of a WIMS, from training, personnel buy-in, and auditing/tracking to verify the effectiveness of the program.

The ever increasing oil and gas exploration and production cost requires highly efficient and safe operation of the existing offshore and subsea equipment and facilities. At the same time, a large number of facilities and parts of the existing infrastructure are quickly approaching or have exceeded their originally designed service life. Many fields, however, still have large amount of remaining recoverable oil and gas reserve which can be profitable if current production equipment's service life can be extended beyond their nominal design, otherwise economic penalty of stopping production or installing new equipment will be too high. On the other hand, once existing equipment have been operating beyond their design life, unforeseen failure and integrity problems can occur that site personnel may have not previously encountered. In many cases this can cause production to cease unexpectedly, and result in costly emergency repairs to get the asset back online. To extend asset life and push the design envelop, operators must prove to themselves and often their regulators that the assets are safe to operate with limited and controlled risks. In a scenario like this, the subsea integrity management of ageing assets has become a key issue for the oil and gas industry. This paper provides an actual case study for asset integrity assessment of subsea facilities life extension, performed by DNV GL and the O&G asset operator team. The study includes the asset integrity condition assessment based on equipment design documentation, operations data, maintenance and inspection analysis data, risk assessment and recommended mitigation of identified threats, engineering critical analysis of high risk equipment, and proposed destructive lab testing of parts retrieved from subsea.

Objectives/Scope Human error and human factors are contributing causes in over 50 percent of well control incidents, according to SINTEF data. While straight-forward cognitive errors and wrong actions contribute to 15 percent of incidents, the larger span of human factors includes communication failures, workload, management practices, and information availability and presentation problems that lead to mistakes, such as imperfect kick detection or underbalanced wells. Yet human factors is often treated as an issue of human reliability estimates and the need to define better procedures that design human error out of the system. There are, however, many shortcomings to the focus on procedures and human reliability estimates, for example, variations among installations, situations that lie outside existing procedures and estimates, and analyses of rote procedure-following that exclude situation variability and expert problem solving. What is needed is a deeper, human factors-centric, approach that looks beneath the procedures for underlying systemic causes: operator situation awareness and decision making, team common ground and collaboration, and resilient socio-technical organizational processes. Our project is taking this human factors approach with a comprehensive analysis of well control during deepwater drilling. Methods, Procedures, Process Our novel approach is to marry the risk management framework of threats and barriers with the human factors concept of the decision cycle. The decision cycle concept outlines the cognitive steps involved in decision making from detection, to interpretation, deciding, and acting. Our innovation is that these concepts can be brought together to identify a set of 117 "human factors barriers" for effective detection of an influx. These human factors barriers support team situation awareness, communication, and decision making. These barriers include the availability and representation of data, user vigilance, support for critical thinking, crew resource management, shift change hand-off processes, system status availability, and change management processes. These human factors barriers can be applied readily to other decisions within well control. Results, Observations, and Conclusions We have created a database of BSEE/BOEM incident reports and reviewed these incidents against the human factors barriers. We have identified a number of "hot spots" or trends where specific human factors barriers were frequently compromised. These trends include sensor placement for situation awareness, shift hand-off processes and team communication, and decision support for critical thinking and diagnosis of uncertain situations. Novel/Additive Information These human factors barriers and the identified trends can be used a) pre-incident to review and audit drilling rigs and well plans to identify and then avoid potential problems, b) post-incident to investigate and report on incidents from a human factors perspective and thereby better inform the industry concerning these topics, and c) to identify key topics for further research and development of improved systems and processes.

Obsolescence can be a significant cost driver and impacts equipment at all stages of the whole life of field. The life cycle of parts within major long life products can be significantly shorter than the life of the products they are within. Obsolescence risk when installing and maintaining existing and future Subsea Production Control Systems (SPSs) is therefore of significant concern to the industry as there is an ever increasing demand to extend the operating life of equipment. Whilst the largest risk is with electronics and electro/mechanical items, the requirement is to manage all types of parts used in the design, manufacture and support of SPSs and associated topside equipment. A Subsea Obsolescence Management Joint Industry Project (JIP) was established to address the significant obsolescence issues being experienced by Oil & Gas operators as they attempt to upgrade ageing infrastructure or repair failures. The objective of the JIP is to make available a recommended practice that could be freely used by any/all operators in the industry, as required. The intention is that a common practice used by all would minimise the different types of methods employed within the major suppliers to manage obsolescence. To help in this respect the JIP has produced a Recommended Practice (RP) for Subsea Obsolescence Management. This recommended practice relates directly to the requirements of a Joint Operator Specification (JOS) that was collaboratively developed by a group of operators and released in 2012. This paper will present the key activities undertaken by the JIP and show how they have implemented, and are continuing to improve, a proactive obsolescence management capability into the Subsea Systems supply base.

The purpose of Bureau of Safety and Environmental Enforcement (BSEE)'s Safety and Environmental Management Systems (SEMS) is to enhance safety of operations in the Gulf of Mexico (GoM) region. One of the four principal SEMS objectives is to encourage the use of performance-based operating practices. However, the current U.S. Regulatory framework for offshore operations in GoM does not provide the adequate tools to focus on the specific risks associated with a facility. The adoption of a Safety Case regime would steer the operations in the GoM towards this goal. Operators could take over the Safety Case as a significant input for the development of their Risk Management and Asset Integrity Management (AIM) programs for existing operating facilities as well as new facilities being planned. The paper discusses the application of a Safety Case and how the Operator can demonstrate that the major safety and environmental hazards have been identified, the associated risks are estimated and how these risks are managed by achieving a target level of safety. Throughout the Safety Case road map, the identification of the Safety Critical Elements (SCEs) and the associated Performance Standards represents one of the corner stone of the AIM Strategy. Introduction of the Safety Case would not imply a complete overhaul of the current Regulation, but would lead to a continuous and adequate enhancement of the Regulatory requirements towards a performance-based approach. It would include a prescriptive-based policy, combined with a performance/goal-oriented process, considering the specific risks inherent to the installations and the demonstration of how these risks are managed. With help of an example the paper discusses how application of Safety Case for existing facilities would highlight particular risks that may have been misjudged, taking into account the current state of its installations and the actual operational procedures in place. Further, this paper shows how existing Risk Management and AIM systems could be revised based on identification of SCEs and definition of the associated Performance Standards. This would also give the Regulator a quantified picture of current operations in the GoM and assist in re-defining the distribution of its resources and efforts in order to have an efficient review and verification impact. For the new facilities, the introduction of the Safety Case at the early stages of design would ease the integration of the overall risk management plan at each level of organization. The Regulator would have the ability to cross-analyze the risk results arising from the Formal Safety Assessment studies with the risk management plan drafted by the Operator. This paper investigates the possible integration of a performance/goal-oriented regime into existing Risk Management and AIM systems.

Flow Assurance (FA) engineers usually produce a range of technically feasible solutions in response to a particular challenge. Often these solutions are cost neutral. In order for a development manager to select the optimum solution he/she examines the risk profiles associated with the options. To progress a marginal development, explicit understanding of financial risk is imperative, needing a step up from qualitative “gut feel” assessments to a more reasoned and auditable quantitative evaluation of FA risk. As part of Woodside's Next Generation Flow Assurance Strategies initiative, Woodside embarked on a Joint Industry Project (JIP) called RiBFAT, standing for Risk Based Flow Assurance Toolkit. The main objective of this JIP is to develop quantitative risk profiles for FA solutions to the wide range of FA challenges. Phase 1 of the JIP produced a Proof of Concept for a risk based approach to hydrate management, one of the main FA challenges of cold ambient temperature field developments, typified by deepwater. Phase 2 was the conversion of the agreed methodology into fully functioning non-commercial software; completed by the end of 2014. This paper discusses the methodology developed and illustrates how this can be applied to a field development concept in order to compare the risk profiles for alternative FA strategies for hydrate management. The risk profiles cover the life of the asset including additions / modifications to facilities as required to optimise the development of the reserves. Ongoing use of the methodology results in the production of a database of knowledge for each FA challenge, which may be interrogated for benchmarking or assurance purposes, allowing the user to develop greater confidence in a particular proposed strategy. The methodology for addressing risk described in this paper will be extended in the next phase of the JIP to other FA challenges such as slugging, scale, wax and corrosion, building up to a comprehensive toolkit for FA risk assessment, including the database. Concurrently, we plan to document this methodology as the first ever global FA risk assessment recommended practice.

This paper will discuss the technical and operational need for regulatory "equivalency" in the emerging Arctic offshore oil and gas industry to address technological innovation, especially in the area of Same Season Relief Well (SSRW) capability. The authors will provide an overview of both the technical and legal framework around which emerging technologies can be evaluated and accommodated in the regulatory approval process. With the rapid pace of technology development continuing unabated, regulatory flexibility is required to ensure that regulations keeps pace with innovation.