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Abstract Permanent surface and downhole measurement technologies have advanced considerably in terms of availability, reliability, performance and costs, and are increasingly deployed for real-time monitoring of wells and equipment. Permanent downhole sensors are used to measure pressure, temperature, flow rates, fluid phases and to reflect operating conditions in wellbores. Surface sensor systems provide real-time measurements of pressure, temperature, fluid phases and flow rates that need to be integrated for analysis. The resulting large volume of data has created challenges in data management, evaluation and analysis. It is important that production analysts have access to workflows and tools that provide real-time efficient and effective visualization and analysis. The optimal approach is to perform the visualization and analysis of data in real time, or near real time, to provide analysts with actionable information for timely and accurate decision making. Permanent downhole gauges are used for monitoring reservoir drainage, injection efficiency, well-completion hardware performance, and downhole pump performance. Some of the resulting benefits include reduced operational costs, improved safety, and properly monitored well integrity. Several onshore and offshore case studies are discussed to demonstrate application of real-time measurements coupled with visualization and analysis techniques to also achieve improved artificial lift performance, reduced operating costs, and manage production. The value of the information obtained from downhole permanent gauges and surface measurements are justified as evidenced by the growing number of operators relying on real-time permanent gauges. This paper reviews technologies that are used to monitor and manage equipment and production in oil and gas wells. It explains that the realized value of permanent monitoring depends on an efficient workflow for collection, evaluation, and analysis.
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Background The Al Rayyan field came on production in 1996, and has from the outset been completed with coil tubing deployed ESPs (CT ESP). The drivers for this type of completion are several. Firstly economic, as these units are installed and pulled using coil tubing with a CT unit permanently located on the platform. This results in significant savings in not requiring a rig, and greatly reduces deferred production losses as no significant mobilization activity is required. Production rates are such that the necessary annular flow can be achieved in 9-5/8C_" casing. The fluid characteristics in the field, low temperature and GOR with no solids production, make this an ideal candidate for ESP artificial lift. Greater detail of these will be set out in the paper. Finally, reliable CT ESP systems were becoming available at the time of early field development, having overcome initial problems such as the optimum method of conveying the ESP cable to the motor. There are currently 14 such systems installed producing from 3500 bfpd to 17000 bfpd. Applications The paper will suggest where CT ESP technology may usefully be applied, either where ESPs are already (given necessary surface modifications), or can beneficially be installed as an alternative to tubing deployment. Where rig availability or cost may result in uneconomic production levels, CT ESPs will be shown to bring several advantages. Not least that workover duration is typically 2 C_- 3 days from pulling to installation and commissioning. The paper will give an overview of pull and run procedures and highlight improvements made in the technique over time. As a result of the necessity to produce via the annulus, there is a requirement for horizontal wellheads to accommodate the coil tubing, the design of which will be discussed. Limitations in terms of deviation, dog leg severity, coil strength and other physical limits will be considered. Particular operating conditions will be discussed, and measures applied to overcome obstacles to stable production explained. Results and Conclusions In lift performance terms, i.e. rate, lift and power demand, these units are identical to conventional ESPs of equivalent specification. The paper will explore the evolution of run life performance since first installation in 1996. Comparison will be made with run life performance of comparable conventional units. An estimate of comparative economics between CT and tubing deployment will be made, as will total number of production days estimated to have been saved over field life. Technical Contributions The paper will consider how, as a result of being one of the first CT ESP produced fields, developments in Al Rayyan led to advances in the technology generally for application elsewhere. This will refer to methods of suspending cable in the coil, a problem which affected the evolution of CT ESP technology for some time. Developments in high rate and high horsepower motors will be explained, as will recent modifications to the ESP intake design to accommodate high rates and velocities through the shroud assembly that is required in CT ESP where the pump is located below the motor. Future developments will be addressed. Continuing development of the technology in partnership with the vendor is an integral part of OccidentalC_'s run life development strategy. Part of this has been to focus on primary failure mode. Increasingly, ESP life has exceed coil tubing life, often associated with corrosion in an H2S environment. Possible R & D work to remedy this will be outlined. Optimum production depends on the availability of downhole data. Presently these wells are completed with a permanent gauge located below the packer which provides an effective measure of down hole flowing pressure. However, to date no ESP gauge, as is routinely installed in conventional ESP completions, has been run. The paper will outline the development of such a gauge and define the benefits in ESP protection and optimization that will result. Future technical developments that are not yet available but would add significant value to the CT ESP system will be outlined. A drawback of the technology as it exists at present is that it is not possible to conduct production logging operations due to the presence of a 7C_" packer below the ESP which the intake stabs into. As the field is comparatively high in water cut, the ability to perform PLTs in the horizontal lateral(s) with subsequent water shut off opportunity would free valuable capacity in separation and disposal systems.
The above scenario lead oil & gas industries to focus technologies from an operator's point of view and
Abstract Fibre optic sensing technology, which involves no operating electronics at the sensing part, has a potential and significance due to the fact that it will offer higher reliability and longer life time of sensors compared to its electrical counterparts. The passive nature of fibre optic sensors also contributes to that such systems will require a minimum of maintenance during operation over several years. No electronics and fewer components of the in-sea or in-well part of such system may make it easier and cheaper to produce than electrical systems of the same capacity. All the existing technology which exists in connection with the instrumented oil field can now be changed from electrical to optical sensing technology. Fibre optic receiver systems for 4D purposes, both multi-component ocean-bottom receiver systems and in-well sensors, can now be installed successfully at locations where the oil companies would like exploit the life-of-field seismic concept. We are advocating optical sensing technology to be an important part of the tool box for the oil companies in their work to implement the instrumented oil field in a cost efficient way. The "optical oil field" should represent the next step in technology in connection with reservoir monitoring for increasing the hydrocarbon recovery rate in a cost efficient way. Introduction The instrumented oil field has been associated with installation of seismic sensors at the sea floor and in producing/injection wells, in addition to pressure, temperature and saturation gauges to monitor a producing well (Lumley, 2001). On-demand 4D seismic and "intelligent wells" can give information to the reservoir engineers close to real-time implying that decisions connected to optimization of hydrocarbon production can be made a lot faster and with greater confidence than before. Up to recently, the sensor technology for both seismic and in-well measurements has been based on electrical components. Electrical sensors may experience degradation in the hostile in-well environment. The telecommunication industry has for several years utilized fibre optic technology in their work to increase band-width and increase life-time of telecom cables. The thin and flexible strands of pure silica glass with thickness of hair has increased the capacity of communication lines within a cable with several factors compared to telecom cables made of copper. Sensors for various measurements, making use of laser light, which is fed through optical fibres, offers a viable and reliable method as an alternative to sensors based on electronics. Fibre optic sensing technology has for the last 5–10 years been available to the oil companies for in-well applications in their work to actively monitor oil/gas flows and injection processes in order to increase hydrocarbon recovery and optimize production. Fibre optic sensors embedded in ocean bottom cables intended for permanent seismic installations at the sea-floor have also emerged as a potential tool for oil companies to utilize information from repeated seismic to better image reservoirs, map reservoir depletion zones and increased understanding of expansion fronts of injection water, drainage areas and connected volumes. This would reduce the risk of encountering water swept areas in a reservoir with future production wells. Due to their passive nature and no electronics, fibre optic sensor systems can offer a huge reliability potential for several in-well applications including seismic imaging (Bostick et al., 2003, Knudsen et al., 2003 and Keul et al., 2005). The environmental conditions are challenging with temperatures possibly up to 200ºC and pressures exceeding 1000 bars. Conventional electrical sensors will always suffer in reliability at such extreme temperatures and pressures. A successful installation of a fibre optic permanent borehole seismic system in an offshore production well has been executed at Valhall in the North Sea (Hornby et al., 2007).