Drawing the flow profile of the three phases (oil, water and gas) downhole is the ultimate goal of production logging. However the flow regimes that develop inside the well bore can be very complex (e.g. stratification, mist, annular, recirculation, etc) and the mapping of the fluid velocities and holdups inside the well bore is key to the proper evaluation of the individual phases flowrates at every depth level along the survey interval. The mapping ability of the present production logging tools is somewhat limited; consequently difficulties are encountered when interpreting data sets that were acquired in such complex downhole conditions at the present time. Flow Scan Imager is a new tool which comprises five mini-spinners, six electrical and six optical probes that get deployed downhole once the tool is across the survey interval. Each mini-spinner will evaluate the localized fluid velocity that is passing by it, whilst each electrical and optical probe will respectively evaluate the localized water and gas holdup that prevail around its place. When deployed, these sensors will be positioned in such a way that their measurements will constitute a map of the fluid velocities and holdups along a vertical cross section of the well bore at every depth level thus enabling a superior estimation of the individual phases flow rates in complex flow regimes downhole. The use of this tool in deviated and horizontal wells will undoubtedly enable the users to better understand their production regimes, to define a more accurate flow profiles and consequently plan more efficient remedial works or production strategies, which will inevitably improve their ultimate hydrocarbon recovery. Introduction Zakum Development Company (ZADCO) in Abu-Dhabi led the initiations of running Flow Scan Imager tool for the first time in one of its deviated wells. It has allowed the clear visualization, for the first time, of water re-circulation downhole in an oil producer where the water cut at surface is zero. This has given the company a better insight into the down-hole conditions. In this paper we will 1) talk about the complexity of the flow regimes that has lead to the development of the FSI*, 2) explain the FSI* tool design features and advantages over previous generations of production logging tools and 3) review the logging results in ZADCO well # 1. Complexity of flow regimes Laboratory experiments have shown that flow regimes that develop downhole in highly deviated wells can be very complex. Figure-1. This is an illustration of the various flow regimes that could develop downhole in horizontal wells
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTwo classes (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCO's standard cement evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response, the reliability of these tools and their interpretations for determining the existence of poor behind casing cement quality and possibly hydraulically communicating layers was critically and systematically examined by a dedicated team of ZADCO and Schlumberger technical professionals. The criteria used to judge the usefulness of these logs was the present or not of communication behind casing as determined by the physical test. For the twenty-eight wells examined, twenty-five of the cement log interpretations matched the communication test results. One well which communicated had 10 feet of apparent good cement with the remainder poor. Its cement log suffered from eccentralization which negatively affected the cement bond log interpretation. Two wells with long intervals of excellent cement on logs suffered behind casing communication. The reasons for this remain unresolved but are a source of constant discussion. Possible explanations for the mismatch between cement evaluation log interpretation and the physical test results are explored.
The first Maximum Reservoir Contact (MRC) wells for a major operating company offshore Abu Dhabi have been successfully designed and implemented. In this paper, the design, optimisation, piloting, field implementation, and post-job field data evaluation for the most critical well are discussed. The re-development strategy for the company hinges on the move to an islands-based development concept. This concept dictates that a significant number of wells be extended reach, long horizontals to maximize reservoir contact and exposure. The increased reservoir exposure will translate proportionally to accrued production (or injection) benefits and value, balanced reservoir sweep, and maximizing recoveries. Hundreds of these MRC wells will be ultimately needed, to maximize recovery and drive the field daily production output from the current level to an increase of at least fifty per cent. However the challenges of designing, drilling and completing these complex wells are new to the operating company. The operator embarked on a program of drilling pilot wells with a view to establishing new learning and understanding, which translates into efficiently designing, deploying and operating these wells for the field re-development. The paper shows the methodologies employed for one of these pilot wells, right from the concept stage through to the modelling, design and optimisation. It also shows how operational considerations were fed into the optimisation workflow, and how the resulting design was implemented in the field. The obtained field measurements such as resistivity, fluid mobility, production logging, production rates were compared to the initial design and performance forecasts, and excellent conformance is demonstrated, further validating the robustness of the implemented designs. The paper highlights the lessons learnt from this exercise, and also proposes a recommended methodology for approaching and adopting the design and implementation of advanced wells, within oil and gas producing assets.
This conceptual study addresses the subject field which has a current expected operating life of more than 100 years, which exceeds the life of the existing facilities. As an alternative to continuing development with Well Head Platform Towers (WHPT’s), the concept of artificial islands holding drilling and production centers has been introduced [ref.1]. The island concept brings enormous flexibility in terms of managing future development uncertainties both subsurface and surface. The new subsurface development concepts include extensive utilization of ERD/MRC wells specifically designed and placed in conformance with geologically defined drainage areas. This strategy predicts significant improvement in plateau duration and sweep efficiency with fewer wells. The new islands based surface plan allows a phased installation of facilities, and space provisions to expand facilities to cater for subsurface uncertainties. It also handles the remnant life issues associated with the existing infrastructure (Wells, WHPT’s, pipelines and trunklines, satellites, central complex). This includes provisions for future requirements in terms of Water Injection, Artificial Lift and Gas Injection and other EOR applications.
This paper presents the application of an integrated modeling approach to the facility design and construction stages of a mega-project for a giant oilfield offshore Abu Dhabi. The scale of the EPC task is unprecedented in the UAE and requires careful design to optimize the capital investment. In addition, the project uncertainties require that a high degree of flexibility be factored into the design process. The integrated modeling approach couples surface and subsurface flow models to achieve a complete system solution that incorporates many levels of constraints and realistically represents future behavior. This approach addresses a number of key issues. Firstly, multiple different quality reservoirs produce to a shared surface facility. Consequently, the field is highly sensitive to back pressure variation and so requires a rigorous treatment of well and surface physics. Secondly, the sub-surface uncertainties and sheer size of the investment requires a flexible approach to design, hence, many simulation scenarios are required to provide improved decision support. Finally, close collaboration is required between the sub-surface and surface teams to ensure optimization of facilities design and reservoir management for cost and recovery. The adopted methodology utilizes an integration framework which couples reservoir and topsides models into a predictive tool for development planning. This paper describes how the integrated modeling approach was utilized to provide input to design process for several aspects of the field development plan during the design and construction stages. This will include discussion of the phasing of the production facilities, requirement for temporary facilities, modular compression and separation units and the optimization of the drilling program for planned infill wells. The paper presents a best integrated modeling practice supporting facility design process which is applicable for similar scale projects, highlighting the role of integrated model as a means to foster collaboration between surface and sub-surface teams.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.