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Collaborating Authors
Reservoir Simulation
Well Planning Under Uncertainty: Application of a Systematic Procedure for Risk Assessment and Uncertainty Analysis for New Well Targets on the Brage Field
Hersvik, Karl J. (Norsk Hydro A/S) | Aanonsen, Sigurd I. (Norsk Hydro A/S) | Petersen, Lasse S. (Norsk Hydro A/S) | Fjellbirkeland, Hege (Norsk Hydro A/S) | Robson, Adrian (Norsk Hydro A/S) | Sperre, Thomas (Norsk Hydro A/S)
Abstract The Norwegian North Sea Brage field came on production in Sept. 1993. The field is currently producing approx. 8000Sm3/d and is on steep decline from its plateau rate of 19400Sm3/d. In March 1999 it was decided to stop the drilling for approximately one year. During this year new reservoir models were built and history matched. Although this work proved to be both complicated and tedious it was fairly successful. However there was still a high degree of uncertainty in the understanding of the flow pattern and the pressure behaviour of the field. It was therefore decided to perform a comprehensive uncertainty analysis to get better estimates of the expected production and risk related to a resumed drilling. The analysis was performed both on a well to well basis and combined into a drilling campaign. The paper will describe analysis in detail illustrated with field examples. A reservoir simulator is utilized to estimate the unconstrained well potential for each well. Then total field water handling constraints is imposed using a tool that optimizes the production given the individual well profiles and the platform constraints. This gives a basis for determining the base case Present Value, PV, for each well's contribution to the field production. For each well target, the most important uncertainties with corresponding probability distributions are identified, and their effect on the PV determined by simulations. In cases where the simulation model is judged not to represent the reservoir behaviour correctly, analytical methods are used. Finally, these results are used together with the drilling cost into a Monte Carlo simulation loop to determine probability distributions for the NPV of each well and for the total drilling program. It is shown that even though most of the individual well targets has a high risk of a negative NPV, the economy of the total drilling program is robust and has a significant upside economical potential. The procedure, which is based on commercially available software only, has proven to be very flexible. It is easy to incorporate new uncertainties related to a well target, or to include or exclude a well target from the drilling schedule. Finally, the resulting NPV probability distributions provide an easy way of ranking well targets based on expected NPV and risk. Introduction The Brage Field is located in the Norwegian North Sea approximately 120 km west of Bergen in Block 31/4, close to and East of the Oseberg Field. The field consists of three separate reservoir unitsFluvial deposits of the lower Jurassic Statfjord formation Shelf to shore-face deposits of the middle to upper Jurassic Fensfjord Formation Shelf to shore-face deposits of the upper Jurassic Sognefjord formation Except for a single well producing from the Sognefjord formation, all the current Brage wells are located in the Fensfjord and Statfjord. Only the Statfjord and Fensfjord formations will be described as all the wells currently planned will produce from these formations.
- Europe > Norway > North Sea > Northern North Sea > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Oseberg Formation (0.99)
- (34 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Management > Risk Management and Decision-Making > Risk, uncertainty, and risk assessment (1.00)
- (2 more...)
Abstract This paper addresses the problem of real time reservoir management and simulation while drilling. A software tool developed for this purpose is also described and discussed. Examples on use of the software are also presented. Introduction Over the last 10–15 years the petroleum industry has, as all industries, constantly faced, derived and implemented new technologies. It is fair to say that the major breakthrough has been in drilling, and some examples are drilling of advanced wells, intelligent wells with remote zone control, drilling speed improvement due to drilling systems such as Autotrak and drilling bits with extended lifetime. These factors have made optimal well location and completion designs a challenging problem. At the same time, R&D in other disciplines has led to improvements in seismic methods and 3D reservoir modeling methods to mention a few. Also, technology push on other areas has faced the industry with advanced visualization concepts, the possibility to use high speed data networks between main office and onshore and offshore sites and of course the use of internet as an information database. The challenge is now to take advantage of the new technology and to optimize existing work processes. The cost and risk associated with drilling a new well is so high that all possible information and tools should be used to optimize well location. But true real time well planning is a fight against time, as drilling speed is one of the technologies that are under constant improvement. Another challenge is how to interpret the new data, sort out the important new information and use it in an optimal way. In this respect, efficient and reliable computer tools are needed. Time is a key factor for decision while drilling, and the time frame to disposal for the decision makers may be quite different, dependent upon the situation. If a pilot hole is drilled, one has in the order of 1–3 days to use the new data and optimize the final well location and trajectory. If a multilateral is drilled, one has maybe 1–2 weeks in optimizing the second branch based on data from the first. The most challenging problem is to modify (geostear) the well trajectory as the well is drilled. Within the area of reservoir simulation, this challenge is often referred to as simulation while drilling (SWD). We will define simulation while drilling as any computer model based software that may help to optimize the problem together with the work process of actually performing these calculations (i.e. data interpretation, model updating and simulation). The work presented in this paper started out in 1997 as a development project between BP (now BP/Amoco), Schlumberger GeoQuest, Norsk Hydro and Saudi Aramco. The idea was to develop a software tool (Near wellbore modeling tool) for optimal well location, completion and modeling of near well bore phenomena. The topic of this paper is simulation while drilling and to our knowledge, few papers in the petroleum literature about this concept exist. In an ongoing research programme at Stanford University (Supri-B program) both analytical and numerical approaches will be considered. A semi-analytical solution that accounts approximately for reservoir heterogeneity will be considered as a base for SWD in the first part of the project. In the second part of the project, the idea is to use SWD with a numerical simulator. Experience with using PC-based reservoir modeling tools on-site is described and studied by Buchwalter et. al. The need for dynamic evaluation is case dependent. In simple (relatively spoken) cases (for instance: two phase flow, close to homogeneous reservoirs, layered models with no dip) analytical methods or simply field experience from drilling similar wells may be sufficient. But in the complicated three phase case with heterogeneities, influence of neighboring wells (infill drilling) and gas and/or water influx, simulation is considered to be the best alternative.
- North America > United States (0.68)
- Asia > Middle East > Saudi Arabia (0.54)
- Europe (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.54)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- (4 more...)
Best Practices and Methods in Hydrocarbon Resource Estimation, Production and Emissions Forecasting, Uncertainty Evaluation and Decision Making
Jonkman, R.M. (International Oil & Gas Services) | Bos, C.F.M. (Netherlands Institute of Applied Geoscience TNO) | Breunese, J.N. (Netherlands Institute of Applied Geoscience TNO) | Morgan, D.T.K. (Uncertainty Management Ltd.) | Spencer, J.A. (Reserves Management Ltd.) | Søndenå, E. (Norwegian Petroleum Directorate)
Abstract On behalf of a group of sponsors consisting of the Norwegian Petroleum Directorate (NPD) and most E&P companies active in Norway, a workgroup was set up to author a report on the Best Practices and Methods in Hydrocarbon Resource Estimation, Production and Emissions Forecasting, Uncertainty Evaluation and Decision Making. The workgroup is part of Norway's forum for Forecasting and UNcertainty (FUN). Following a detailed data acquisition and interviewing phase to make an inventory of the current practice of all sponsors involved, the workgroup postulated a relationship between a company's practices and its economic performance. A key distinguishing factor between companies is the degree to which probabilistic methods are adopted in integrated multi-disciplinary processes, aimed at supporting the decision making process throughout the asset life cycle and portfolio of assets. Companies have been ranked in terms of this degree of integration and best practices are recommended. In many companies a gap seems to exist between available and applied technology. Data and (aggregated) information exchange between Governments and companies is also discussed. A best practice based on their respective decision making processes is recommended. Introduction Norway's forum for Forecasting and UNcertainty evaluation (FUN, ref. 1) was established in 1997, and has 18 member companies plus the Norwegian Petroleum Directorate (NPD). The forum is a Norwegian Continental Shelf arena to determine best practice and methods for hydrocarbon resource and emissions estimation, forecasting uncertainty evaluation and decision making. It focuses on matters related to forecasting and uncertainty evaluation of future oil and gas production. Its main purpose is to optimize the interplay between the private industry and the national authorities wishing to regulate their national assets. The basic question that kicked off the FUN Best Practices project was whether the accuracy of Norway's historical production forecasts has been disappointing because of erroneous contributions from the companies or because of wrong aggregation by NPD. The question was posed which "Best Practices" could improve this situation. Whereas reserves form the basis for production, capex, opex and emissions forecasting, the decision making process in the various companies and national authorities links the various components together. Using the latest WPC/SPE guidelines for reserves reporting (allowing the use of probabilistic methods), the project concentrated on assessing the potential advantages of probabilistic techniques when used in combination withfully integrated asset management workflow processes. After a discussion of the current practices of the various companies and authorities visited, "Best Practices" are formulated in the fields of estimating reserves, production, costs and emissions forecasting, decision-making, planning and communications. The paper concludes with recommendations on how to move from the "current practices" to the desired "Best Practices".
- North America > United States (1.00)
- Europe > Norway (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.54)
- Government > Regional Government > North America Government > United States Government (0.47)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- Management > Risk Management and Decision-Making > Decision-making processes (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Optimising Performance of Mature Reservoir: An Innovative Use of Coiled Tubing Drilling Technology to Tap Unswept Reserves, Alwyn North UKCS
Lheure, S. (TotalFinaElf Exploration UK plc) | Müller, S. (TotalFinaElf Exploration UK plc) | Kimber, R. (TotalFinaElf Exploration UK plc) | Holehouse, S.G. (TotalFinaElf Exploration UK plc)
Abstract This paper describes the rationale, the planning and the preliminary results of the first Coiled Tubing Drilling (CTD) experience for TotalFina. The objective was to enhance production from a high water-cut oil well producing under unstable conditions and located in an area of possible upsides. This well was drilled in 1990 on the edge of a fault-scarp degradation complex in the Brent East panel of the Alwyn Field. The geological uncertainties in this complex area needed to be reduced and it was necessary to reassess seismic, core and reservoir data to progress the current knowledge base. Analytical calculations supported 3D reservoir modelling techniques to constrain some of the uncertainties. Drilled in 1999, well 3/9a-N30Y was the first coiled tubing sidetrack from a producing well on Alwyn. The motherbore, 3/9a-N30, was still producing around 380 stb/d, although production had recently become intermittent. The well path presented a challenging trajectory due to the location of the unswept area in relation to the direction of the motherbore. After drilling 240m a series of operational issues arose, necessitating the drilling of the world's deepest open hole sidetrack with coiled tubing, but ultimately the BHA was left in hole. The coiled tubing was then utilised as an uncemented liner, perforations using slim guns were added along the liner, and the well was brought onto production. The CTD drain alone produced at an initial rate of 2900 stb/d, which stabilised out at 1200 stb/d after an initial rise in water cut. The successful outcome of 3/9a-N30, which was drilled in a complex offshore environment, confirmed the viability of CTD as a technique for accessing smaller pockets of remaining oil, whilst some of the operational difficulties encountered highlighted the need to simplify future trajectories to maximize the chance of success. With the possibility of drilling future CTD wells, further increases in productivity and reserves will be achieved at a significantly lower cost compared to conventional drilling. Introduction and Background Field Discovery, Appraisal and Development. The Alwyn North field (blocks 3/4a and 3/9a) is owned at 100% and operated by TotalFinaElf Exploration UK (Fig.1). It is situated in the South-eastern part of the East Shetland Basin in the UK North Sea, approximately 140km east of the Shetland Isles. The field was discovered in 1975, with gas and condensate in the Upper Triassic and Lower Jurassic Statfjord Formations, and undersaturated oil in the Middle Jurassic Brent Group. These reservoirs are separated by the Lower Jurassic Dunlin Group shales. The Brent reservoir pressure was initially 453bar at 3231mTVDMSL, and the Statfjord 496bar at 3580mTVDMSL. The field is divided into distinct compartments by a major NNW-SSE trending fault and by secondary ENE-WSW transverse faults. The major "spinal" fault separates the field into East and Western panels, while the transverse faults subdivide the western panels into North, North-West, Central-West, and South-West panels. Oil production commenced in November 1987 from the Brent reservoirs, followed by gas and condensate from the Statfjord reservoir two months later. Field Discovery, Appraisal and Development. The Alwyn North field (blocks 3/4a and 3/9a) is owned at 100% and operated by TotalFinaElf Exploration UK (Fig.1). It is situated in the South-eastern part of the East Shetland Basin in the UK North Sea, approximately 140km east of the Shetland Isles. The field was discovered in 1975, with gas and condensate in the Upper Triassic and Lower Jurassic Statfjord Formations, and undersaturated oil in the Middle Jurassic Brent Group. These reservoirs are separated by the Lower Jurassic Dunlin Group shales. The Brent reservoir pressure was initially 453bar at 3231mTVDMSL, and the Statfjord 496bar at 3580mTVDMSL. The field is divided into distinct compartments by a major NNW-SSE trending fault and by secondary ENE-WSW transverse faults. The major "spinal" fault separates the field into East and Western panels, while the transverse faults subdivide the western panels into North, North-West, Central-West, and South-West panels. Oil production commenced in November 1987 from the Brent reservoirs, followed by gas and condensate from the Statfjord reservoir two months later.
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/8 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/3 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/29 > Brent Field (0.99)
- (12 more...)
- Well Drilling > Drilling Operations > Coiled tubing drilling (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
Hysteresis in Three-Phase Flow: Experiments, Modeling and Reservoir Simulations
Egermann, P. (IFP: Institut Français du Petrole) | Vizika, O. (IFP: Institut Français du Petrole) | Dallet, L. (GDF: Gaz De France) | Requin, C. (GDF: Gaz De France) | Sonier, F. (SMC: Simulation & Modelling Consultancy)
Abstract The viability of miscible WAG injection as an EOR scheme for the Magnus reservoir is under consideration. Performance prediction and optimization under this type of recovery mechanism, in which the residual oil is usually recovered by a multi-contact miscible (MCM) process, rely mostly upon compositional simulation. Unfortunately, numerical dispersion effects, associated with large grid blocks required in field scale compositional simulation of MCM processes, can result in erroneous phase behavior. Reduction of dispersion to acceptable levels may require very small grid blocks, implying model sizes that exceed the capacity of current conventional computer installations. Thus, full field compositional models are not practical for reliable field-wide benefit predictions. This paper presents a systematic procedure that we successfully employed for prediction of field wide performance and recovery benefit of miscible WAG injection for the Magnus reservoir. The procedure involves an extension of the upscaling technique proposed by Fayers et al [1]. It starts with a 3D fine grid compositional sector model of a small representative element of the reservoir. Then, this reference model is upscaled to block sizes corresponding to those in the Magnus full field model (FFM), using the single-phase half-cell upscaling technique. The upscaled model employs the Todd and Longstaff (T&L) formulation [1,2] for simulating MCM displacement and three-pseudo components for representing phase behavior. The PVT, solvent equilibrium constants and miscibility pressure vs. composition tables are developed through matching with a calibrated 12-component equation of state (EOS) and 1D slim tube simulations, for a wide range of pressure and composition. The PVT treatment also allows for vaporization of oil by the contacting gas. To calibrate the model, the upscaled transmissibility values had to be further adjusted in order to match the reference single-phase pressure/rate performance for several horizontal and vertical flow orientations. The base waterflood performance matching was achieved for a couple of potential well orientations by adjusting water-oil relative permeability curves. The final stage involved determining the T&L mixing parameters through calibration of MCM WAG displacement performance with the reference fine grid compositional model. This approach led to a set of T&L mixing parameters, which result in a very encouraging match between the upscaled and the reference model. Calculated WAG recovery is more sensitive to the viscosity rather than density mixing parameter, indicating a moderate tendency for gas gravity override. Further sensitivities were performed to examine the robustness of the calibrated upscaled model against variations in operating parameters. The results confirm that the upscaled model satisfactorily matches the reference model in terms of variations of the benefit with slug size and WAG ratio. The determined T&L mixing parameters were then implemented with confidence in the Magnus T&L FFM for predictions of field-wide MCM WAG benefit, returned gas (injected gas produced) volume and composition, and water and gas lift gas requirements post EOR. We also discuss impacts of various uncertain parameters on the performance of MCM WAG injection, which were investigated using the calibrated upscaled model, taking advantage of about 1000 times gain in CPU time compared to that for the reference fine grid compositional model.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.66)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Abstract Should future regulation of the use and release of E&P chemicals offshore focus more on tests of chronic effects at low levels of contamination, in line with recent ecotoxicological discoveries? Within this context, what groups of E&P chemicals are relevant, and what kind of effects and test methods should be incorporated in revised regulations? Can this altered but more relevant environmental focus potentially be beneficial for both the environment and the oil E&P sector? This presentation will discuss and answer these issues. Introduction There is an increasing concern about long-term impacts on marine organisms by chronic operational discharges from petroleum exploration and production (E&P) activities offshore. Apparently, there is a general shortage of knowledge about potential long-term effects of E&P chemicals released during these operations [1]. It may be questioned whether the sets of methods presently used for environmental evaluation of current discharge procedures and for toxicity ranking of E&P chemical products are sufficiently relevant, or whether more relevant test protocols and new effect evaluation approaches are needed. Over the past decade, new links between environmental pollutant exposures and the occurrence of putative adverse effects in aquatic organisms have been discovered. Several commonly used chemicals are now regulated more strictly or are even part of a phase-out process due to such new knowledge; one example is the nonylphenol derivatives. A range of new biological monitoring tools has also been developed enabling us to detect effects in laboratory exposed organisms at more environmentally realistic contaminant concentrations, and also to perform more relevant ecotox effect studies in field recipients. Projects initiated by petroleum companies have been launched in order to develop screening protocols for determining the potential environmental impact of E&P related contaminants on the marine ecosystem, e.g. [2]. However, the main volume of this work has been directed towards the use of standardized toxicity screening tests and bioassays, rather than supporting effect studies in which more relevant marine species are being exposed under conditions which are more realistic to a recipient situation (combined exposure, low-dose/long-term treatment, etc.). Ecologically relevant impact phenomena may rather occur in waters where contaminants are highly diluted (chronic low dose), and less in the ultimate mixing zone of the effluent stream (figure 1). The three main objectives of this paper are (1) to provide a brief insight in how ecotoxicity of chemicals and effluents from E&P operations are considered at present. (2) To briefly review the recent progress within the field of (marine) ecotoxicology. (3) To discuss the relevance and benefit of including updated effect measurement techniques for evaluating impact of E&P chemicals and effluents being released to the marine environment.
- North America > United States (0.47)
- Asia > Brunei (0.29)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (6 more...)
Abstract This paper will firstly introduce the method of diffusion coefficient measuring in situ. Then the presentation is to be given that the diffusion coefficients of demulsifier AP between toluene and water are measured by isotopic labeled and liquid scintillation counting technique; The affection of NaCl on the diffusion behaves of demulsifier AP211 is also discussedin this paper. Introduction The demulsification of crude oil is a common problem in the oilfield. But there remains surprisingly little scientific date regarding the exact details on how demulsifiers work in crude oil emulsions. The present study attempts to understand the mechanisms of demulisification. It has been observed that there was closed relationship between demulisifier performance and the diffusion coefficient of demulisifier molecular. The result from Young-Ho et al. demonstrated that if we plan to enhance the effectiveness of demulsifier, the interface tension gradient which is on the interface film must be decressed. So, a high diffusion coefficient and a high interface activity are essential factors. The quantity of demulsifier used was too little, which makes the measurement very difficulty. And there were many limits on the measurement of the diffusion coefficients of demulsifier if we take some common methods. Therfore, the method of isotopic labeled and liquid scintillation counting technique is selected in this paper to measure diffusion coefficient of demulsifier. There are several unique advantages in this method. Theory We consider the system Toluene-Water-Demulsifier, with the demulsifier dissolved in one of the two immiscible phases. When a fresh surface is formed between a demulsifier solution and a second liquid, the mass transfer of the demulsifier would occur. The demulsifier molecular will diffuse toward the interface and enter the other phase. Janos et. al divided this process into a series steps, and concluded that the mass transfer of demulsifier is a diffusion controlled. The diffusion step obeys the Fick second law:Equation 1 Under the condition of confirmed concentration, we haveEquation 2 We assume the diffusion face is the interface, X=0, so, we can caculate the number of molecular that through and approach the interface from t=0 to t=t. Equation 3 in which C0 is the bulk concentration of the demulsifier, D is the diffusion coefficient of the demulsifier. When we used the counting technique of isotopic labeled and liquid scintillation, we can count the number of demulsifier approach and cross the interface and the number of those finally go into the toluene phase. The demulsifier in the water phase does not influence the counting result. So, when we plot the C to t, we can get the diffusion coefficients of the demulsifiers. Experimental Material The demulsifier, which labeled by H3 isotopic used for this paper was synthesized in our laboratory, and the products were defined by NMR. Table 1 lists the ratios of EO and PO that in the demulsifiers. The water in all experiments is redistilled, and all of the other reagents were analysis grade.
- Asia (0.47)
- Europe (0.28)
- North America > United States (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Dynamic Simulation of a Realistic 3-D Model of the Brent Slumps
Dijk, H. (Shell U.K. Exploration and Production) | Arnott, S. (Shell U.K. Exploration and Production) | Ozoglu, S. (Shell U.K. Exploration and Production) | Pritchard, D.W. (Shell U.K. Exploration and Production) | Price, S. (Shell U.K. Exploration and Production) | Snippe, J. (Shell International Exploration and Production B.V. )
Abstract Facing with the constant challenge for improved plant reliability at a lowercost, today's Asset Managers have been looking for various ways and means torationalize their business activities. Being a major part of the businessmanagement system, maintenance discipline is also responding to this call. While the maintenance approach has gone through a series of evolutionarychanges over the last 30 years, the managers are now looking for a moremethodical and structured framework for analyzing and recommending themaintenance needs. Reliability Centered Maintenance (RCM), which takes aholistic approach encompassing integrity, health, safety, environment, financial, technology and human resources is designed to provide such aframework. Since a large number of text books and publications are available on thissubject, this article will mainly address PDO's experience in utilizing the RCMmethodology through a project and some "Dos" and "Do Nots" based on theauthor's learning points. A brief background on the RCM methodology is providedfor the readers who may not be familiar with the RCM process. 1. Introduction RCM is literally defined as a risk based analysis process used to determinewhat is to be done in terms of maintenance to ensure that any physical assetcontinues to do whatever its owners want, within its operating context. Although, the RCM has been in use for decades, starting with the Aircraftindustry and is now widely used in the chemical and the petrochemicalindustries, Exploration & Production (E&P) companies have just startedto realize the benefits of this methodology. PDO initiated the use of a classic RCM methodology for a number of its SouthOman fields almost four years back. The recommendations from these analysiswere implemented over the last two years in some of the fields. However, due toboth lack of proper understanding of the RCM approach and inefficient executionprocess, the Company could not realize the real benefits in its implementation. It is to be noted that while the use of the RCM methodology is intended torationalize the maintenance routines with possible cost savings withoutcompromising integrity, its real success should be seen in capturing theintangible benefits e.g., an "attitude" and "cultural" change in approachtowards maintenance, which is what the RCM does best. So far, this has not beenachieved in PDO. In order to realize the benefits of RCM in its true sense in 1999, the newlyformed Reliability Management section in PDO was tasked to take a moreintegrated team approach and to use new, user friendly RCM software developedby various Shell Companies. Accordingly, a project with a team of maintenanceconsultants was set up in September 1999 to carry out RCM analysis for all theNorth Oman facilities. The objective of the project is to provide the AssetManagers with an optimized maintenance package, identifying cost benefits, where achievable. A number of Performance Indicators (PIs) will be establishedto measure and monitor these gains in short and long terms. Whilerationalization of maintenance routines and realizing cost benefits are themain objectives, the project puts emphasis on bringing every one in the AssetTeams and the Service providers together on board to create a change in the"mind set" towards "effective maintenance". The initial results have already shown some definite cost savings inmaintenance and these savings have been already booked in the maintenancebudget for year 2001. The project team is encouraged to note that not onlythere is ample evidence of enthusiasm amongst the staff members from both theAsset Teams and the Service providers, the Management team is also fully behindthe project (fig. 1). The success of the project will however, be largelydependent on the effective implementation process over the next couple ofyears. The Company is presently looking into the feasibility of utilizing a"Total Reliability Management" approach in its business. Should this become areality, the RCM project may very well provide the spring board for all thefuture efforts.
- North America (0.69)
- Europe > United Kingdom > North Sea > Northern North Sea (0.29)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline (0.70)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- (5 more...)
Welcome. (1) Structure. The objective of this session is to share with you the concept of the Shell EP Global Open University. I have structured the presentation around:Introduction, Shell External developments, Corporate universities. Description of the Global Open University, key pillars. The benefits for the business. 1. Introduction, Shell. (2) The part of Shell I am going to talk to you about today is Shell International Exploration and Production, and in particular a new approach to learning and development in STEP, Shell Technology EP in co-operation with our many Operating Units across the world. 2. External developments, the Growth of Corporate Universities. Organisations around the globe have very clearly adopted the corporate university concept. The concept involves a process - not necessarily a place - by which all levels of employees, and sometimes customers and suppliers, participate in a variety of learning experiences necessary to improve job performance and enhance business impact. Although the actual number of corporate universities is difficult to pinpoint, some estimates that more than 2000 exist in the United States alone. More importantly, the trend continues to grow. While it began in North America, it has spread to Europe, Asia and the rest of the world in a more limited manner. Organisations have invested heavily in this concept, sometimes as high as 5 percent of payroll costs. This also leads to the training and learning solutions functions in organisations are shifting their focus to performance improvement. The implementation of a variety of learning experiences and non-training solutions. To improve performance in the organisation represents a tremendous change in the way the training and development function is organised, managed, and operated to provide a full array of programs and services. Training and development's roles, skills, and outputs are drastically changing as the staff members transform from their current roles into a group of capable performance improvement specialists and consultants. Collectively, these important external trends from the basis of the key parts of the response from Shell we will come back to. In light of these significant changes Shell has been through and still are doing so, the developments of knowledge management, competence of staff and learning and development had to undergo a significant change. The response from the Professional Learning unit was to develop a concept for making all these elements integrated and contributes effectively to the business bottom line. The answer we developed was our own version of the Corporate University concept: 3. The Shell EP Global Open University The deliverable of the ‘EP Global Open University’ is a skilled, flexible and global workforce to meet EP's business requirements today and in the future. (3) Why is the focus on a competent workforce? The business driver – The Exploration and Production business today The EP business has been through advances in technology and radical changes in business demand brought about by low oil prices, and the prediction of continuing uncertain oil prices. Accelerated deployment of new technology, increase production, pro-active portfolio management and E - Business are high on the business agenda. This situation has changed customer needs, which are driven by the objectives of Strategic Cost Leadership, Global Procurement, Commercial mindset and Leadership skills. At the same time, enormous improvements in communication and information technology possibilities have brought about great changes to the business of learning, training and knowledge management. The organisational driver – a global staff pool Resourcing of people in EP has gone through fundamental changes over the last two years. The EP business has up to now been well served with having a mix of regional staff and some international staff with work assignments normally for 3–4 years. With the drive towards one global workforce, Operating Units who will also offer the first assignments for new graduates will do global recruitment. The business driver – The Exploration and Production business today The EP business has been through advances in technology and radical changes in business demand brought about by low oil prices, and the prediction of continuing uncertain oil prices. Accelerated deployment of new technology, increase production, pro-active portfolio management and E - Business are high on the business agenda. This situation has changed customer needs, which are driven by the objectives of Strategic Cost Leadership, Global Procurement, Commercial mindset and Leadership skills. At the same time, enormous improvements in communication and information technology possibilities have brought about great changes to the business of learning, training and knowledge management. The organisational driver – a global staff pool Resourcing of people in EP has gone through fundamental changes over the last two years. The EP business has up to now been well served with having a mix of regional staff and some international staff with work assignments normally for 3–4 years. With the drive towards one global workforce, Operating Units who will also offer the first assignments for new graduates will do global recruitment.
- Europe (1.00)
- North America > United States > Texas (0.68)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (5 more...)
Abstract The Borg Field is a stratigraphic trapped field of a shallow marine beachline system in the Tampen area of the Northern North Sea. The 30 MSm oil field is currently being developed with 2 injectors and 2 producers as a satellite field to the adjacent larger Tordis and Gullfaks Fields. As a result of the Upper Jurassic play, more reserves are possible to add as satellite developments. The Borg Field proves the Upper Jurassic Volgian-Ryazanian syn-rift deposit to be economically favourable. In the hunt for reserve replacement this play is expected to be important in the Tampen area, but however increasingly harder to predict and locate. The presence and location of additional reserves has been integration of multi-disciplinary data. On the Borg Field pressure data acquired through RFT measurements in exploration wells indicated that the field was pressure depleted before production onset. By analysing pressure data from regional producing fields and exploration wells, this depletion is likely to be caused by production in the Statfjord Field to the Southwest. The oil migration into the Borg Field was interpreted to follow a route from the deep mature basin to the Statfjord Field and to the Borg Field along Upper Jurassic hanging-wall slumped and turbidite sand stones draped along the main Statfjord Fault. These were amalgamating with paleo-beachline sediments lining a restricted bay and finally connected to the Borg Field sandstone on the other side of the paleo-bay. These sand stones can be partially mapped on seismic data and are encountered in exploration / appraisal wells and forms the likely path of pressure communication between the Borg Field and the Statfjord Field. These oil traps have a stratigraphic nature and both the location and size of the reservoir sands are difficult to map location and size of directly from the seismic, however the sands can be of economically importance due to their close proximity to nearby producing fields. During seismic work on the Borg Field, a northern segment was observed detached from the southern segment by a fault zone. A paleo beachline and a delta fan could be predicted by seismic character and through AVO analysis these "seismic-geo-bodies" where likely to be "sand-filled". The Borg Field was initially test produced for 6 months. During this test an influx of pressure was seen when the pressure dropped below the Statfjord Field, verifying earlier observations of pressure depletion from Statfjord, now being an influx. From analytical analysis of these data, the magnitude of the influx where calculated depending on pressure difference between the 2 fields. Well test analysis indicated that an additional volume was present outside of the main Borg Field. Through data integration in a reservoir model and sensitivity testing through the history matching process the presence of an extra volume of 15 MSm was predicted. This volume should be located to the north, to match timing and pressure of a production RFT, which corresponds to the seismic and geologic model. In addition a pressure influx from the Statfjord field mimicked by a pseudo injection well was required in order to math the final build up periods. This prediction of volumes and location, has impact on the reservoir development of the southern segment, the timing and type of exploration / appraisal methods and possibly on infrastructure investment for the whole area. The seismic methods utilised where verified by pressure analysis and can now be used to find similar type of sediments outside of the area "seen" by the production test. Introduction Block 34/7, situated on the central-western side of the Tampen Spur on the Norwegian Continental Shelf, was originally developed by Saga Petroleum ASA until their acquisition on January 1 2000 by Norsk Hydro ASA.
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.86)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.54)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Tampen Area (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Lunde Formation (0.99)
- (54 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)