Successful Application of a Robust Link To Automatically Optimise Reservoir Management of a Real Field
Abstract: 1. Abstract Realistic modelling is essential for both the planning and the optimal operation of Oil and Gas Fields. Such a model for modern well or field development architecture requires coupling of the reservoir simulator with the well/surface facility network model when making choices as to the reservoir and production management strategies to be employed. Such close coupling is not, currently, readily available; particularly when the reservoir simulator, the well/surface facility simulato… Show more
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Cited by 3 publications
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Horizontal and multilateral completions are a proven, superior development option compared to conventional solutions in many reservoir situations. However, they are still susceptible to coning toward the heel of the well despite their maximizing of reservoir contact. This is due to frictional pressure drop and/or permeability variations along the well. Annular flow, leading to severe erosion "hot-spots" and plugging of screens is another challenge. Inflow Control Devices (ICDs) were proposed as a solution to these difficulties in the early '90s. ICDs have recently gained popularity and are being increasingly applied to a wider range of field types. Their efficacy to control the well inflow profile has been confirmed by a variety of field monitoring techniques. An ICD is a choking device installed as part of the sandface completion hardware. It aims to balance the horizontal well's inflow profile and minimize the annular flow at the cost of a limited, extra pressure drop. Fractured and more heterogeneous formations require, in addition, the installation of annular isolation. The new technologies of Swell Packers and Constrictors can provide this annular isolation in an operationally simple manner. This paper describes the history of ICD development with an emphasis on the designs available and their areas of application. These technical criteria will be illustrated using published field examples. The ICD's flexibility will be shown by its integration with other conventional and advanced production technologies e.g. Stand-Alone-Screens, annular isolation, artificial lift, gravel packs and intelligent completions in both horizontal and multilateral wells. It will be shown how the value of such well-construction options can be quantified using commercially available, modelling simulators. Simple, but reliable, guidelines on how to model the performance of ICDs over the well's life will be provided. This technique can thus be used as part of the value quantification process for both the evaluation of completion options and for their detailed design. 1 Introduction Horizontal and multilateral wells are becoming a basic well architecture in current field developments. Advances in drilling technology during the past 20 years facilitated the drilling and completion of long (extended reach) horizontal and multilateral wells with the primary objective of maximising the reservoir contact. The increase in reservoir exposure through the extension of well length helped lower the pressure drawdown required to achieve the same rate and enhance the well productivity 1–2. Major operators have proved the advantages of such wells in improving recovery and lowering the cost per unit length. The production from thin oil column reservoirs (e.g. The Norwegian Troll Field) became a reality thanks to such wells 3–4. However, the increase in wellbore length and exposure to different reservoir facies came at a cost. Frictional pressure drop caused by fluid flow in horizontal sections resulted in higher drawdown-pressure in the heel section of the completion, causing an unbalanced fluid influx. Hence, coning of water and gas toward the heel of the well was observed. Variable distribution of permeability along the wellbore also results in variation of the fluid influx along the completion and an uneven sweep of the reservoir. Annular flow is another challenge often encountered when horizontal wellbores are completed with Stand-Alone-Screens (SAS) or with pre-perforated/Slotted liners. Neither of these completion options employs any form of isolation between the casing and the formation (i.e. external casing packers). Annular flow, which is dependent on many parameters such as the size of the clearance between the sandface and the liner (screen) outer diameter, still imposes several problems including: dislodging of the sand grains causing erosion of the sandface, formation of "hot-spots" and plugging of the sand screens 5–6. Previously, the elimination of such phenomenon required the utilization of gravel packs or installation of Expandable Sand Screens (ESS), which often had a significant impact on the well productivity and/or involved a very complex operation 6–7.
Horizontal and multilateral completions are a proven, superior development option compared to conventional solutions in many reservoir situations. However, they are still susceptible to coning toward the heel of the well despite their maximizing of reservoir contact. This is due to frictional pressure drop and/or permeability variations along the well. Annular flow, leading to severe erosion "hot-spots" and plugging of screens is another challenge. Inflow Control Devices (ICDs) were proposed as a solution to these difficulties in the early '90s. ICDs have recently gained popularity and are being increasingly applied to a wider range of field types. Their efficacy to control the well inflow profile has been confirmed by a variety of field monitoring techniques. An ICD is a choking device installed as part of the sandface completion hardware. It aims to balance the horizontal well's inflow profile and minimize the annular flow at the cost of a limited, extra pressure drop. Fractured and more heterogeneous formations require, in addition, the installation of annular isolation. The new technologies of Swell Packers and Constrictors can provide this annular isolation in an operationally simple manner. This paper describes the history of ICD development with an emphasis on the designs available and their areas of application. These technical criteria will be illustrated using published field examples. The ICD's flexibility will be shown by its integration with other conventional and advanced production technologies e.g. Stand-Alone-Screens, annular isolation, artificial lift, gravel packs and intelligent completions in both horizontal and multilateral wells. It will be shown how the value of such well-construction options can be quantified using commercially available, modelling simulators. Simple, but reliable, guidelines on how to model the performance of ICDs over the well's life will be provided. This technique can thus be used as part of the value quantification process for both the evaluation of completion options and for their detailed design. 1 Introduction Horizontal and multilateral wells are becoming a basic well architecture in current field developments. Advances in drilling technology during the past 20 years facilitated the drilling and completion of long (extended reach) horizontal and multilateral wells with the primary objective of maximising the reservoir contact. The increase in reservoir exposure through the extension of well length helped lower the pressure drawdown required to achieve the same rate and enhance the well productivity 1–2. Major operators have proved the advantages of such wells in improving recovery and lowering the cost per unit length. The production from thin oil column reservoirs (e.g. The Norwegian Troll Field) became a reality thanks to such wells 3–4. However, the increase in wellbore length and exposure to different reservoir facies came at a cost. Frictional pressure drop caused by fluid flow in horizontal sections resulted in higher drawdown-pressure in the heel section of the completion, causing an unbalanced fluid influx. Hence, coning of water and gas toward the heel of the well was observed. Variable distribution of permeability along the wellbore also results in variation of the fluid influx along the completion and an uneven sweep of the reservoir. Annular flow is another challenge often encountered when horizontal wellbores are completed with Stand-Alone-Screens (SAS) or with pre-perforated/Slotted liners. Neither of these completion options employs any form of isolation between the casing and the formation (i.e. external casing packers). Annular flow, which is dependent on many parameters such as the size of the clearance between the sandface and the liner (screen) outer diameter, still imposes several problems including: dislodging of the sand grains causing erosion of the sandface, formation of "hot-spots" and plugging of the sand screens 5–6. Previously, the elimination of such phenomenon required the utilization of gravel packs or installation of Expandable Sand Screens (ESS), which often had a significant impact on the well productivity and/or involved a very complex operation 6–7.
Well performance prediction is a key Petroleum Engineering task. However, large discrepancies between Petroleum Engineering models and reality still frequently occur; despite the continuous increase in the complexity and predictive quality of reservoir models. To-day's field development decisions are still made with a high level of uncertainty in the underlying data and its economic impact. The degree of data uncertainty is greatest during the exploration stage, but decreases as the reservoir development plan is executed and production data is obtained. Standard, probabilistic workflows have been developed to quantify this uncertainty. These workflows are usually framed by the reservoir scale development plan and end prior to the well's detailed completion design. This is despite the fact that expensive, advanced completions have become common during recent years and the additional investment in such completions can only be justified if it is shown to be paid-back by improved overall project economics which is subject to a significant level of uncertainty. This paper illustrates the quantification of the long-term benefits of advanced completions using the probabilistic approach. It will be shown how choice of the optimum advanced completion design will reduce the impact of geostatistical uncertainty on the production forecast. Geostatistical realisations of a benchmark reservoir model were generated with a suitable level of data uncertainty. The reservoir was developed by a single horizontal well in a fixed location. The well could be equipped with a variety of completions - an Open Hole with a sand control screen or a perforated pipe, Inflow Control Devices (ICDs) and Interval Control Valves (ICVs). The probabilistic (P10, P50, P90) oil-recovery distribution was then used to identify the optimum completion design. This completion not only achieved the largest recovery, but also showed the least uncertainty in this value. 1. Introduction Well performance prediction is one of the major tasks when preparing an oil or gas field development plan. The complexity and predictive quality of models used to support this activity have increased significantly during the last two decades, partly driven by the ever decreasing cost coupled with the increasing power of computers However, large discrepancies between the model and reality still frequently occur. They stem from:The lack of data (e.g. the unknown distribution of petrophysical properties in reservoir).Deliberate simplifications to make the problem more tractable (e.g. upscaling, black oil PVT models, neglect of thermal effects, etc.).Computational (sub-grid) errors andAn incomplete understanding of the physics and chemistry of the subsurface. Petroleum researchers still work on the more precise description of the laws governing hydrocarbon production (e.g. multiphase flow, relative permeability effects associated with gas condensate flow in porous media, effect of water salinity on oil recovery, etc.). Many E&P development decisions are made under a high level of uncertainty. The degree of uncertainty and its impact on decision making is naturally greatest at the exploration stage of the field development process. This is one reason why a probabilistic analysis is part of reserves estimation and other standard workflows used in making early development decisions. The predictive accuracy of reservoir models should increase as the field development proceeds since the quality and the quantity of reservoir data will continually increase. Reservoir models should be continually updated by field production data, history matching, and the ever increasing number of (logged) reservoir penetrations. However, uncertainty quantification always remains an important task; even during the later, more mature phase of reservoir development.
Advanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow-Control Completions
Summary Well architecture advances from conventional wells to horizontal. Then multilateral wells, which have maximized reservoir contact, have been paralleled by advances in completion-equipment development. Passive inflow-control devices (ICDs) and active intervalcontrol valves (ICVs) provide a range of fluid-flow control options that can enhance the reservoir sweep efficiency and increase reserves. ICVs were used originally for controlled, commingled production from multiple reservoirs, while ICDs were developed to counteract the horizontal well's heel/toe effect. The variety of their applications has proliferated since these beginnings. Their application areas now overlap, resulting in it becoming a complex, time-consuming process to select between ICVs or ICDs for a particular well's completion. This publication summarizes the results of a comprehensive, comparative study of the functionality and applicability of the two technologies. It maps out a workflow of the selection process on the basis of the thorough analysis of the ICD and ICV advantages in major reservoir, production, operation, and economic areas. It provides detailed analysis of Reservoir-engineering aspects, such as uncertainty management, formation heterogeneity, and the level of flexibility required by the developmentProduction and completion characteristics, such as tubing size, the number of separately controllable zones, the completion of multiple laterals, and the value of real-time informationOperational and economical aspects, such as proper modeling, gas-and oilfield applications, equipment costs and installation risks, long-term reliability, and technical performance. The results of this work's systematic approach form the basis of a screening tool to identify the most appropriate control technology for a wide range of situations. This selection framework can be applied by both production technologists and reservoir engineers when choosing between passive or active flow control in advanced wells. The value of these guidelines is illustrated by their application to synthetic- and real-field case studies.
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