In CO 2 storage projects, CO 2 usually enters the target reservoir at a lower temperature than that of the surrounding rock and its density is increased. The injection temperature affects how much CO 2 can be stored. In this work we investigate the impact of heat exchange during CO 2 injection into the Surat Basin, Australia, using integrated reservoir modelling. We evaluate the aquifer storage and sealing capacities, as well as pressure build up and CO 2 plume migration. Flow simulations of CO 2 injection into the Precipice Sandstone were conducted with injection temperature from 40 to 80°C. The modelling domain consists of the reservoir sandstone, an overlying transition zone (muddy sandstone) and above it, the ultimate seal. The distribution of porosity, permeability and capillary pressure is heterogeneous. Heat exchange between rock and fluids was enabled in the commercial simulator to evaluate changes in fluid properties due to wellbore cooling. The initial temperature was set to 80°C. The injector’s wellbore pressure drop is modelled honouring a constant well head pressure of 15,000 kPa. The maximum allowed bottom-hole pressure is 90% of a thermally reduced fracturing pressure. The viscosity of water and CO 2 increases during cooling of the near wellbore zone; thus, pressure build up grows faster in the case of lower injection temperatures. Although the bottom-hole pressure becomes higher, injection rate is constrained by well head pressure. Heat exchange also increases the density and saturation of CO 2 at the plume edge, which causes a sharper and faster advancing front. Higher pressure in the reservoir forces fluids to migrate to the transition zone, which also reduces its temperature. CO 2 flows preferentially through the lowest capillary pressure channels and is able to permeate slightly into the transition zone. These physical conditions at the bottom of the well (lower temperature and higher pressure) lead to a denser CO 2 plume and a greater mass is stored in the reservoir each year. This work analyses non-isothermal injection of CO 2 into an aquifer using integrated reservoir modelling. It illustrates how reservoir cooling may increase the rate of CO 2 storage and slight migration to the transition zone.

Interpretation of subsurface lithology has been an integral part of bottom-hole investigation while drilling a well for hydrocarbon exploration. Conventional methods such as mud logging and open-hole logging have proven to be effective in this aspect. But there arises a need of the real time interpretation of subsurface drilling lithologies to have a better control over desired well path and economics, which is very limited through available conventional methods. This paper aims to provide a classifier that can deliver a justified chance of success in lithology estimation based on input matrix provided to the classifier. The dataset is taken from open source platform (Equinor), which provided the drilling history of 15_9_F_15_D well of North Sea Basin along with the interpreted lithology. This dataset is used to prepare the input matrix and the corresponding output used for the classifier. It incorporates seven drilling parameters, i.e. rate of penetration (ROP), weight on bit (WOB), bit rotation per minute, total bit rotations, corrected drilling exponent, mud flow & mud weight and the corresponding recorded subsurface lithology for each foot. It is made sure that the chosen drilling parameters have a direct impact on the rate of penetration with changing physical characteristics of the formations being penetrated. The formations are calibrated with the integer values from 1 to 5 for easier numerical computations. The prepared dataset is divided into two components i.e. training Set (80%), and test Set (20%) with feature scaling implemented. The most intuitive classification model among all the tested classification algorithms i.e. multiple classification algorithm, artificial neural network, and KNN search method is stated based on their individual F (1) score on the test set. It is observed that the cost function for the multiple classification model stopped reducing after the first few iterations irrespective of learning rate value alterations, which induced a limit on the accuracy provided by the chosen algorithm. It is observed that the performance of ANN is quite good for the lithology present in majority, such as claystone. However, the performance degrades exponentially for the lithologies occurring in minorities such as sandstone, dolomite, marl and limestone. The results obtained from KNN classification model not only provides an accuracy of 95% in claystone, 92% in sandstone and 89% in marl which makes this model the most appropriate classifier to be used among the three. The preliminary results, through the comparison among the three classifiers not only provides the most intuitive model for subsurface lithology prediction using real-time drilling data, but also gives an idea about the most appropriate classifier to be used in the future reference, be it any basin, given that the same set of drilling parameters are used as the input matrix for training the classifier.

Organisations have long recognised the potential for diverse teams to improve overall creativity, innovation and productivity, thereby achieving consistently better business outcomes - the so called ‘diversity bonus’. This is particularly true and relevant to the oil and gas industry, which constantly has to manage technical and economic uncertainty, major operating hazards, and continually seek business performance improvement and efficiencies, in order to operate sustainably and meet ever higher stakeholder expectations. However, developing successful diverse teams presents practical questions and challenges, including what type of diversity will really add value to a task, how will a diverse group of people relate to and support one another, how can major innovation be delivered consistently whilst working within highly structured management systems and standards which aim to achieve a high degree of consistency and minimise failure frequency, and what is the most useful role of the manager/leader for such teams? This paper describes diversity and inclusion in its broadest sense, and its benefits and challenges within the context of the oil and gas industry, in particular with regard to Petroleum Engineering and subsurface teams. A number of common and practical industry situations are considered, and the merits of further opportunities are discussed. The fundamental actions and behaviours that help oil and gas companies promote and establish more diverse and inclusive teams and cultures, in order to deliver outstanding results, are examined.

CO 2 geo-sequestration can significantly contribute to the reduction of greenhouse gas emissions. Out of all geological CO 2 storage sites, mature oil fields are often considered primary targets for CO 2 sequestration as one of Carbon Capture, Utilisation and Storage (CCUS) approaches where the operation cost can be offset by enhancing oil recovery and utilising the existing facilities. However, a geological formation with large volumetric capacity (pore volume) is not necessarily an appropriate candidate for CO 2 storage and CO 2 injectivity plays equally an important role for site selection to store CO 2 . Therefore, evaluation of CO 2 dynamic storage capacity (injectivity) and ultimate CO 2 enhanced oil recovery (EOR) are key elements for a successful CO 2 storage – EOR project. CO 2 EOR was considered as a suitable tertiary oil recovery approach after very short and inefficient primary and secondary oil recoveries in Yanchang oil field, the second largest tight oil field in China, located at Ordos Basin in north western China. This paper describes the acquisition of essential dynamic data from a reservoir in Yanchang oil field to evaluate its CO 2 injectivity/dynamic storage capacity. For that, numerical reservoir simulation was utilised to model and history match the target reservoir. The history matched model was then used to numerically perform several testing scenarios resulting in the selection and design of the most appropriate test. A unique two-stage well testing approach was proposed to inject water and CO 2 into one well and observe the pressure at two monitoring wells for a total testing period of about one year. It accurately estimates formation effective permeability in both the water flooded zone (test stage 1) and the CO 2 flooded zone (test stage 2) at the injecting well. Also, it qualitatively estimates the water and CO 2 fronts in the reservoir as well as CO 2 injectivity using data at the injecting well. The radius of investigation (ROI) significantly increases by adding two monitoring wells to the existing injecting well. Using two monitoring wells also identifies heterogeneities and lateral anisotropy in the reservoir. The recently acquired field data, as part of this well testing program, indicate that the reservoir characteristics at the monitoring wells are significantly different from each other, suggesting the existence of considerable heterogeneity/anisotropy in the reservoir. The results generated by this well test are included in the reservoir model to reduce uncertainties for the future CO 2 -EOR field development plan. Finally, more informative decisions can be made on whether or not a field is suitable for a CO 2 -EOR project to unlock further oil resources from tight formations.

One of the challenges faced by companies in the oil and gas industry is the difficulty in assessing and quantifying subsurface uncertainties when planning for hydrocarbon exploitation. A commonly employed approach is to use available exploration and appraisal data to produce a range of possible subsurface realisations, through which hydrocarbon production forecasts are generated. Prediction of hydrocarbon production from these simulations are then used to assess the viability of a planned development concept and the associated subsurface uncertainties. However, due to the sparsity of field data and unpredictability of underground geology coupled with the typically large dataset sizes, the ability to rapidly quantify prediction uncertainty and provide an overview of the range of underground geologies leaves much to be desired. Here we show that the application of a network science approach to oil production prediction data provides an intuitive way to visualize and assess reservoir uncertainty. A network transformation utilizing Pearson correlation and mean absolute error as similarity measures were applied to a dataset containing time series predictions of oil production for 10 wells simulated in 50 different subsurface realisations. Realisations were generated using a synthetic reservoir spanning 20 years of production. It was found that the network representation enabled the inference of reservoir uncertainty by simple visual inspection. Additionally, network measures such as the beta index were used with results supporting their viability in quantifying uncertainty. The application of clustering algorithms to the resulting networks was also shown to simplify the time series into component characteristic subsurface realisations. We propose a method to quantify subsurface uncertainties and create a simplified representation of the characteristic modes associated with a range of subsurface realisations, greatly reducing the time required to conduct a cursory analysis. Our results demonstrate how the application of network science ideas may be applied to provide new ways of analyzing production data and performace predictions. These methods provide an opportunity to further refine descriptions of uncertainty by incorporating stochastic elements into the network as well.

In the recent decade, injection of nanoparticles (NPs) into underground formation as liquid nanodispersions has been suggested as a smart alternative for conventional methods in tertiary oil recovery projects from mature oil reservoirs. Such reservoirs, however, are strong candidates for carbon geo-sequestration (CGS) projects, and the presence of nanoparticles (NPs) after nanofluid-flooding can add more complexity to carbon geo-storage projects. Despite studies investigating CO 2 injection and nanofluid-flooding for EOR projects, no information was reported about the potential synergistic effects of CO 2 and NPs on enhanced oil recovery (EOR) and CGS concerning the interfacial tension (γ) of CO 2 -oil system. This study thus extensively investigates the effect of silica NPs on the γ of CO 2 /decane system at elevated pressure and temperature to recognise the potential impact of NPs-injection on the future CGS projects. To achieve this, a wide-ranging series of tests have been conducted to reveal the role of hydrophilic and hydrophobic silica NPs on γ of the CO 2 /oil system. n-decane was utilized as model oil and different amounts of NPs were mixed with the oil phase. Oil-NPs dispersions were formulated using an ultrasonic homogenizer. The γ of the CO 2 /oil system was measured at different pressures (0.1 to 20 MPa) and temperatures (25 to 70 °C) using a high-pressure temperature optical cell. The γ data were measured using the pendant drop technique via axisymmetric drop shape analysis (ADSA). The results showed that, generally, CO 2 /oil γ subjected mainly to pressure, temperature, and with less extent to NPs load in the oil phase. γ decreases with increased pressure until reaching a plateau where no more significant decrease in γ was observed. The γ trend with increased temperature, on the other hand, was more completed. No significant impact of temperature on γ was recorded with low pressure (≤ 5 MPa). Similarly, at relatively high pressure (≥ 25 MPa), only a slight variation of IFT with temperature change was recorded. However, for the pressure range from 5 – 25 MPa, IFT was increased remarkably with temperature. Furthermore, NPs in the oil phase exhibit a remarkable influence on IFT. In this context, the presence of hydrophilic silica NPs in the oil phase can significantly reduce the γ of the CO 2 /decane system. However, hydrophobic silica NPs showed less influence on IFT reduction. The outcomes of this work afford good understandings into applications of NP for EOR and CGS applications and help to de-risk CO 2 -geological storage projects.

A new quantitative model of water channeling identification in unconsolidated sandstone reservoir is presented that uses the hierarchical analysis and grey correlation method as its basis for calculations. By analyzing the influential factors of water channeling, seven static factors including sedimentary micro-facies, oil viscosity, permeability, porosity, reservoir type, heterogeneity and cementation degree which impact the formation and development of water channeling are studied, and six dynamic factors including water injection index, injection/production well pressure difference, liquid production index, water cut, production/injection ratio and sand production rate which indicate the appearance of water channeling are confirmed. Used the hierarchical analysis and grey correlation method, the weights of static factors and dynamic factors are calculated, and the new identification model of water channeling is established. In the new identification model of water channeling, there are six different geological models lead to different fluid flow law in the reservoir, which is conventional zone, high permeability zone, micro- fracture in reservoir, and macro-fracture in reservoir, part-completely developed water channeling and full-completely developed water channeling. Using the new method proposed in this paper, the characteristics of water channeling in a practical reservoir group are analyzed. And the quantitative identification results are proved by tracer monitor results. The testing result of tracer is the same as the quantitative identification method, that is to say the new method is effective and accurate.

This paper identifies several best practices for improving employee competency and productivity. They include aligning reward and promotion practices with company core values, promoting those who are already leading and have the capacity to perform at the next level, and using both internal and external benchmarking to help employees to set stretch goals for competency training and improving productivity.

Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [ 1 ] available in the open literature. A review of more general studies on two-phase gas-water flows in vertical pipes and annuli revealed that experimental conditions, especially pipe and annuli diameters, can have a significant impact on development of two-phase flow phenomena. As such, the limited available data may not be applicable due to differences in experimental conditions. This study experimentally investigates the onset of gas carryover using an experimental setup intended specifically for the study of CSG wells. The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.

Gas injection methods such as Continuous Gas Injection, Water Alternating Gas and conventional Gas-Assisted Gravity Drainage (GAGD) have been widely used to improve/enhance oil recovery for conventional oil reservoirs. However, applications to naturally fractured basement reservoirs are still limited. This paper will introduce a case study of a new and effective GAGD method conducted in a Huff ‘n’ Puff fashion to improve oil recovery for a fractured basement reservoir in Cuu Long Basin, offshore Vietnam. A GAGD pilot, which consists of 4 cycles, was conducted in which dry gas was periodically injected into an existing production well in an isolated area. It was expected that as the injected gas rose to the top to form a gas zone, it would push the Gas Oil Contact (GOC) downwards and might also push the Water Oil Contact (WOC) to the lower part of the producer or even away from the bottom of its wellbore. Before commencing the 4 cycles, gas injection, asphalting and reservoir simulation studies were conducted. In addition, a thorough forward plan was carefully devised before each cycle to determine possible effects of important operating parameters to the final outcome of that cycle. From the results of the 4 cycles, it could be concluded that the gas injection volume is well correlated with cumulative water-free oil production, a parameter which indicates the effectiveness of the method in terms of the gravity-drainage mechanism. It could also be found that the final incremental oil gain of each cycle depended upon, not only, the gas injection volume, but also other important factors such as gas injection, shut-in time… suggesting that a non-linear optimization exercise is necessary to make the whole pilot economically successful. The success of the GAGD pilot proves that it could be a simple and effective Improved Oil Recovery (IOR) method for fractured basement reservoirs. That can be a foundation for further application of the method to other reservoirs in the Cuu Long Basin.

Based on a review of the leadership literature and personal observations, the author proposes a new leadership model for engineering managers (EM) in today's petroleum industry. This model consists of five essential leadership attributes. They are technical leadership, task leadership, relational leadership, change leadership and authentic leadership. Technical leadership refers to the ability of the EM to manage projects that are technically complex, multi-disciplinary and are subject to a high degree of technical uncertainty, such as field development planning. Task leadership refers to the EM's ability to be result- focused so as to complete the project on time, within budget and according to scope. Relational leadership refers to the EM's ability to motivate, challenge and support his or her team members to do their best. Change leadership refers to the EM's ability to promote innovative improvements to the organization and adaptation to external changes. Authentic leadership, which underpins all other leadership attributes, refers to the EM's ability to lead according to his or her core values which are ethical, commendable and consistent with those of his or her company, key stakeholders and the community. Suggestions on what universities, companiesand technical professionals can do to provide or acquire leadership training are also given.

The downhole communication is the key technology of reservoir exploitation and downhole remote control. The vibration wave communication method provides a new way for the downhole data transmission. Using this method, control commands can be modulated and transmitted through the tubing or casing by the vibration wave. To analyzing the downhole transmission characteristics of vibration waves, a field test was implemented in the Daqing oil field. The vibration signal generator, located on the wellhead, can convert the electricity into the vibration wave by using the magnetostrictive material. The vibration wave signal is transmitted through the casing. To receive and test the signal, a signal detection device is developed. The signal detection device can be fixed on the casing firmly at any depth by a motor-activated-ram mechanism. A cable is plugged into the signal detection device, with which the detected vibration wave signals and the decoded signals can be transferred to the computer on the ground. By analyzing the received signals, the following conclusions are drawn: (1) At the depth of 900 meters, the vibration wave signal can be received and decoded correctly, which verifies the feasibility of the vibration wave downhole communication method. (2) Detection failure of vibration waves of certain frequencies occurs at specific depths. This phenomenon proves the characteristic of alternating passband and stopband in vibration wave transmission, which also validates the reliability of the multi-fundamental-frequency transmission strategy. (3) The attenuation characteristic of the vibration wave is obtained. With its low cost, convenient operation and high reliability, the vibration wave downhole communication technology can be widely used in hydraulic fracturing, water flooding and zonal production.

Safety and safe behavior at various universities, especially in Indonesia, are still neglected and sometimes this failure to observe safety in lab activities end up with accidents that can be minor such as lost sample, up to major with bodily injury or fatality. As graduates from universities are source of new-hires for the industry, having high-quality graduates that are versed in safety would improve the quality of incoming new-hires and possibly reduce the onboarding process within oil companies. To improve the condition at various university laboratories in Indonesia, Chevron IndoAsia Business Unit (Chevron IBU), has developed a 4-day workshop, called as "Good Laboratory Practices" (GLP) Workshop, that shares industry’s best practices in: safety and safe lab behavior, flammable and combustible materials, basic fire prevention, lab waste management, lab business plan, statistical data analysis, sample custody chain, lab accreditation, and Fundamental Safe Work Principles. This well-received workshop has been conducted sixteen (16) times, since the inception in late 2006, and will be continued with 4 similar workshops this year. These workshops were conducted to 7 universities and a national lab in Indonesia, attended by lab managers, lab operators, graduate students and other personnel. As each attendee would interact with students, either during classroom or lab sessions, this workshop has been estimated to influence close to 5000 students in improving their safety and safe behavior, This paper would share the challenges in developing the workshop and initial resistance from university professors, quick hitter and best practices as the program comes to maturity.

The three pillars of main activity on oil and gas sectors are the ABG (Academy (university), Business entity (company), and the Government). A synergism of these three pillars should be strengthening in building a sustainable growth of oil and gas business. The relationship could be in any activities amongst them, such as the universities are supporting the intake of workforces and well trained developing people for the industry (company). The companies accept the graduated students and give a sponsorship for the research in the university. The government produces the rules for business and support funds for the university. As a professional organization IATMI (Society of Indonesia Petroleum Engineers) tried to stimulate a better relationship among the A-B-G. IATMI had continuous linked activities between the universities and the companies which is a bridging program for graduate students to have information of job fair, scholarship, or research grants. The IATMI also support the company to have a better access for new research and technology development in the universities, socialization of new regulations and policies from the government, etc. This paper reviews the role of IATMI as an experienced professional organization in Indonesia’s oil gas sectors. The discussion will focus on how important of a synergism among the ABG and the results of the IATMI initiatives in last decade supporting and stimulating the business of oil and gas in Indonesia.

The oil business uses a large quantity of water during the drilling and completion of an unconventional gas well. In many of the shale plays each well needs in excess of 4 million gallons of water (100,000 bbl) during the drilling and completions operations. Water is a precious resource and many areas are faced with water shortages. Water shortages extend to almost all the traditional oil and gas producing areas in the United States including Colorado, California, Wyoming, Texas and Oklahoma. Also, the arid areas of Australia, The Middle East, and Africa see even more severe shortages of fresh water than in the United States. Moreover, in areas where water is not in short supply such as Indonesia, Malaysia, and the Eastern United States, discharge of high salt content water is problematic. In order to assure itself of adequate water for drilling and completion operations, the oil business needs to change the ways it has traditionally transacted its business. As stated above many drilling areas are faced with water shortages, whereas many other producing areas are faced with high disposal costs for frac flow back water and produced water. In many traditional production areas disposal of water is simple and usually inexpensive since there are numerous injection wells in these traditional production areas. However, in some of the new Shale plays the access to injection wells for disposal of produced water and frac flow back water is very limited. Part of the solution is to recycle the frac flow back water and the produced water for use as drilling fluid or for Frac Fluid. How clean does this water need to be for use as a drilling fluid or a frac fluid? What techniques are used to clean this water? How costly are the various techniques? These questions and others will be addressed in this paper.

Abstract The X gas field of PDO is currently contributing of Oman's gas requirements for LNG export. The field is producing from the rich gas-condensate bearing Reservoir A and lean gas bearing Reservoir B and Reservoir C sandstone. The total number of wells until to date is 23 development wells drilled in the field, of which 11 wells are on production, 6 wells produce from Reservoir A only, 1 well from Reservoir B only, 3 are commingled Reservoir A, B and C, 1 well from Reservoir A and C, and last, 1 well from C. The average formation split from the field predicted 45% Reservoir A, 20% Reservoir C and 35% Reservoir B, and in specific is vary from well to well and however it is depend on the drawdown. The primary surveillance tool is used to allocate a relative production for two reservoirs by utilizing a MPLT surveys. And recently, a campaign of multi-phase flow meters coupled with PLT's was initiated. Gases in Reservoir B and C reservoirs of Oman have very different carbon isotope character than those in Reservoir A. These differences are unique and can be used to calculate mixing proportions of commingled production. The proposed solution to this problem was the derivation of two and three case models that accounts for variable isotope and composition characteristics, and trending in which all such data could be correlated. The effectively of this geochemical technique is captured from this study. Introduction Geochemical technique by gas chromatography and isotope analysis processing can bring solution to the problem of properly allocating gas production to specific reservoirs when more than one formation is commingled in a well.

Abstract Incident investigation and analysis is an essential part in identification of risks and managing the business process. The quality of the investigation and analysis determines on what level remedial actions can take place. The better the investigation and analysis, the more one finds the systemic causes of incidents. By identifying and remedying these systemic causes, entire classes of incidents can be prevented. Based on the Tripod theory, Tripod Beta has been developed as an instrument to analyse incidents. Tripod Beta is seen as a state-of-the-art method to analyse incidents. The method itself however is not explicitly designed for fact-finding, although the Tripod Framework does give a clear direction and supports finding facts. This paper describes a new tool in the Tripod family: TRACK. TRACK facilitates the process of fact-finding and enables the investigator to get away from the "what happened" to the "what made it happen". Results show that using TRACK increases the consistency and objectivity of the investigation, and forces the investigator to dig deeper than with any other tool available. Introduction Since the publication of Human Error in 1990 1 a consistent trend in the interest in the contribution of human error to industrial accidents can be noticed. The common factor in this trend is the theory that prevention of human error is most effectively gained by controlling the working environment instead of focusing at the individual who ‘failed’. 2,3 Safety does not, as many experts believe, depend on the number of sprinklers and hydrants installed, but a high proportion of accidents and catastrophes are the obvious result of management error. 4 According to Rasmussen 5 accidents are the result of lack of control: ‘A closer look at major accidents indicates that the observed coincidence of multiple errors cannot be explained by a stochastic coincidence of independent events. Accidents are more likely caused by a systematic migration toward accidents by an organization operating in an aggressive, competitive environment. [..] Safety is a control problem.’ To prevent human error a range of techniques are available, some more effective than others. Initiatives like Unsafe Act Auditing, Qualitative Risk Assessment and Technical Safety Auditing are in many companies applied to increase safety. These techniques may be necessary but are not yet sufficient to further decrease the number of accidents. Essential in trying to improve the safety state of individuals is to acquire insight into the situations that lead to accidents and how those specific situations can be avoided. These factors are not only present at the work floor but also at other supervisory and managerial levels. The most successful ones focus on the managerial responsibility in identification and elimination of adverse conditions at the workplace. Due to the complexity of dynamic organizations, management cannot develop fail-safe long-term solutions. They should therefore not focus on the complete elimination of human error and the corresponding dynamics of human behaviour by enforcing strict compliance with procedures but on the soundness of their organization. They have to control the processes they initiate to remedy deficiencies in the structure of the organization.

Introduction How adequately are engineers prepared to meet the challenges of the industry today, using various tools such as competencies, development programs, and state-of-the-art training techniques? This paper will describe a global development and competency framework for technical personnel that both describes and tracks job competencies to the task level, with respect workflow processes, through the three points below: Utilizing blended learning techniques (combination of instructor-led activity, online training, simulations, seminars, and university programs) will provide the means of developing knowledge. By participating in development programs, engineers will work under a mentor to learn the application of a particular role, of skills and of behaviors that are associated with the role. The competency process, as the gateway, will be used to assess and ensure that all knowledge, skills, and behavior are sufficient to perform tasks in accordance with company standards With challenges and issues of the energy industry today and in the future, the three tier development approach has been proven to be an effective process to prepare engineers for the field technical roles. The effectiveness of the process will be demonstrated from both the theoretical and practical viewpoint. Blended Learning A key element in the development of competent technical personnel in the energy industry is an effective learning process. Learning provides the knowledge component of competency. Historically, the learning path starts in university and continues with company-led or sponsored courses. The path was then further augmented over time with either university or professional society based activities. The majority of the activities were instructor-led in a classroom environment. In times of ample, singly focused, technical staffing and predictable business cycles, this path provided an adequate means of knowledge acquisition. During the last decade, however, a more effective means of delivery has become a necessity. Geographically widespread technical resources, time away from office and duties, travel related costs and travel difficulties due to world events, as well as the diverse learning styles of a wide experience-band of engineers have driven the need to develop new techniques of learning delivery. Learning for engineers is generally characterized as technical. However, in today's flat organizations and in view of need for multi-tasking, effective learning in leadership/management, HSE, financial, inter-personal skills, and cross training are necessary. Thus, a learning system must be appropriate, flexible, and timely. An effective organizational learning strategy must be developed to utilize each approach effectively, provide maximum value to the learner, and be cost effective. Advantages of blended learning Blended learning has several distinct advantages that meet the needs of today's business climate. Training is a costly investment in terms of finances and time and must provide the maximum return. Blended approaches are designed to take maximum advantage of the strengths of each learning process. For example; online learning is appropriate for imparting basic knowledge where large amounts of student/instructor interaction are not required. Virtual classrooms can make use of the interactivity of a live class and instructor while permitting engineers to participate at their home, location, or office. Considerable savings can thus be realized in travel costs as well as in time away from the workplace. Simulators give the learner the opportunity to both obtain knowledge and skills and then to practice their assigned tasks with immediate remediation as part of the process as required. Instructor-led training will continue to be an important approach. However, the trend will be towards teaching in a workshop or applications mode rather than imparting basic knowledge. When prerequisite knowledge for attendance at an instructor-led session is obtained by means of online or simulation methods, the interactive learning can move more rapidly and effectively.

Abstract A numerical model has been developed that is able to predict the onset of sand production and evaluate the performance of sand control, should sand production becomes unavoidable. The simulation of perforation stability was carried out first using a two-dimensional, two-phase finite-element model. This is a coupled geomechanical and fluid flow model. The rock was assumed to be heterogeneous and the pores were completely filled with fluid. The deformation condition is considered as plane strain and either the Mohr-Coulomb or Drucker-Prager yield surface was used to designate perforation failure. The model enables the study on the effect of perforation pattern and density on wellbore stability. Simulation runs on a sample model indicated that the lowest pore pressure, the greatest shear stress and minor principle stress were found close to the perforation tip. The greatest major principle stress occured around the center of perforation roof. In other words, the perforation was always surrounded by high stress concentration. In those events when sand production is a certainty, it is necessary to evaluate the performance of sand control methods to be used. A finite-difference flow model was used to calculate the additional pressure drop from the well boundary to the sand control screen. The Forchheimer equation was used in place of the more conservative Darcy equation so that the effect of high-velocity flow to the well performance could be considered. The result of several sample runs indicated firm relationship between total additional pressure drop and the flow rate imposed, where a larger flow rate will cause greater pressure loss. Also, the well productivity showed improvement with more shots per foot. The results suggested that the majority of well pressure drop was caused by the casing-cement tunnel. Development of Numerical Model In an integrated approach to sand production problems, we seek to predict the stress state around the wellbore for different operating conditions, and if sanding is inevitable, the optimum gravel-pack configuration is chosen. The tools involved are a coupled mechanical-fluid flow model and a three-dimensional well productivity model. The essential equations for the two models are given below. The Perforation Stability Prediction Model In predicting the perforation stability, the borehole is divided into slices. The number of slices depends on the thickness of each slice and the borehole radius. The deformation condition for every slice is considered to be of plane-strain type and the oil flow is confined within the domain of each slice. The perforation is assumed to be a cylinder with an open end, the other end being semi-spherical. Fig. 1 shows a slice with one perforation cavity. The interactions between slices are considered by taking into account the stress component that act between the slices.

Abstract Proper modeling and simualtion of naturally fractured reservoirs is one ofthe most important and challenging issues in reservoir engineering. A dualporosity or dual permeability approach is applied in simulation when fracturesform a flow network. On the other hand, single continuum model, where thefracture system is represented by effective permeability, is commonly used iffractures are discrete or disconnected. Focusing on the letter case, this paperpresents a numerical model that incorporates full tensor permeability in eachgrid block to accurately simulate behaviors of discretely fractured media. We formulate a flux continuous model using the mixed finite volume elementmethod where the pressure equations, expressed as two coupled first-orderpartial differential equations for pressure and velocity, are solvedsimultaneously. This minimizes the numerical errors occurring in standardmethods caused by differentiation of pressure and then multiplication by roughcoefficients. The saturation equation is to be solved by an implicit pressureexplicit saturation approach. Numerical examples of simulating flow in fractured reservoirs are presentedto demonstrate the performance of the proposed simulator. The reservoir modelsfor simulation are two-dimensional and include regularly or stochasticallydistributed discrete fractures. Effective permeabilities calculated by thecomplex variable boundary element method are assigned to grid blocks. The samemethod is used to obtain reference solutions of the tracer propagationperformance in the five-spot pattern. The examples validate importance ofaccurate representation of the full tensor permeability for simulation ofnaturally fractured reservoirs. Introduction Flow of fluids in a naturally fractured reservoir is physically complex. Itinvolves heterogeneity in matrix rock and fracture networks at different lengthscales. Numerical modeling of naturally fractured reservoirs is commonlyconducted through the use of discrete or continuum methods. The dual porosityand dual permeability formulation of the flow equations both assume that thefractures form one continuum and the matrix forms another. On the other hand, the single continuum model represents the fracture system and matrix byeffective permeability. Calculating the effective permeabilities of grid blockspermits the inclusion of realistic fracture features into a continuum model.Also, it accounts for flow coupling between the fracture and the matrixsystems 1 . It is known that the transport and diffusion/dispersion terms in the flowand transport equations are governed by fluid velocities 2 . Thusaccurate numerical simulation requires accurate approximations for thesevelocities. Often the flow properties of the porous media change abruptly withsharp changes in lithology. Also, the viscosity changes rapidly in space acrossfluid interfaces. Consequently, the coefficients in the flow equations becomequite rough. In order for fluids to flow smoothly, pressures change extremelyrapidly. Standard finite difference and finite element methods for solvingthese flow equations determine pressures, and then calculate velocity bydifferencing the resulting pressures and multiplying it by the roughcoefficients. This approach generates a rough and inaccurate velocity, whichthen harms the accuracy of numerical simulation of the fluid flow in porousmedia 2 . Also, the geologic structure and topography of porous mediacan have a significant impact on the flow. Finite volume methods with harmonicaveraging of the coefficients, which has been very popular in the numericalsimulation of flow in porous media, cannot accurately model the geologicstructure and topography. On the other hand, mixed finite element methods haveproven to be very powerful in overcoming the difficulties mentioned above forthe standard methods 3–11 . They can effectively treat the problem ofrapidly changing flow properties in porous media, and produce accurate fluidvelocities. Further, they conserve mass locally; this property is veryimportant in physics since the flow equations are based on the mass balancelaw.