A number of tests were performed in Yamburggasdobycha Gazprom's fields in Northern Siberia area to evaluate the performance of multiphase flowmeters in gas-condensate reservoir applications. The remoteness of the operation and the roughness of winter weather conditions combined with the complexity of the fluid compositions create unique challenges to the successful acquisition of well test data. The paper discusses the challenges and potential benefits of deployment in line multiphase flowmeters in the difficult operating environment of Northern Siberia. The reduced logistics and the ability to monitor in real time the true evolution of the gas and condensate wells provide an in-depth view of the actual well performance. The evolution of the real dynamics of the wells stabilization after a change of choke can be observed and monitored accurately with the in-line Venturi - Dual Energy gamma ray multiphase flowmeter. The importance of the hydrate detection and mitigation processes is essential in the performance of successful tests in the Siberian gas well environment. The paper details the methodology of the comparison of the well test rates of gas and condensate against traditional means of measurement presently deployed in Siberia. It is based on a rigorous mass balance approach, which enables to consider properly the mass transfer effects when comparing flowrates at different measurements conditions of pressure and temperature. The presence of hydrates despite the extremely low water content of the effluent is detected by the multiphase flowmeter, which therefore provides also confirmation of the hydrate build up curve. The challenges to collect representative samples of condensate and gas to ensure proper set-up of the multiphase flowmeter and thus the correct computation of gas and condensate rates are presented, and a number of solutions are described. A discussion of the validity of samples for full reservoir fluid characterization provides insights on the benefits and limitation of sampling in multiphase flow combined with proper conditioning of the samples. The paper further elaborates on the comparison of the fluid composition between traditional surface sampling methods and multiphase testing methods. The utilization of the dynamic information obtained from the multiphase flowmeter to complement the understanding of the reservoir performance is discussed. Introduction Recent advances in the wet gas multiphase well testing have recently enabled the measurement in the field of reliable rates of gas, condensate and water in gas, and condensate wells. The need for inline measurement has been made more acute in the last few years to tackle the following issues:Mitigation of the carry over in gas line out of conventional separatorIncreasing need for high resolution of GCR measurements to determine changes in fluid properties on choke changesHigher repeatability measurements to confirm slow trendsCircumventing hydrate formation issues downstream of surface production chokes plugging up controls in separatorsRemote unmanned operationsLowering of risk associated with well testing in gas well operations through elimination of active control systems and reduction of the volumes of pressurized hydrocarbons contained in the testing systemsPermanent monitoring requirements More of these requirements for wet gas well testing have already been presented in Theuveny et al [1]. The basics of the gas well testing with dual energy gamma - venturi multiphase flowmeters have been shown by Pinguet et al [2], Hopman et al [3] and Guiese et al [8].
Due to increased hydrocarbon demand and technological advances, production from heavy oil fields in the United Kingdom Continental Shelf (UKCS) has become possible over the past 10 years. Despite substantial reserves in the UKCS with crudes less than 20° API, most of the activity has been confined to exploration and appraisal drilling. The main reason for the restricted activity has been the high uncertainty of the reservoir and fluid properties. Operational complexities inherent to heavy oil also limit the use of conventional appraisal-well testing technology.A method was developed to determine the most suitable technology for testing wells with heavy oil using an electrical submersible pump (ESP). The solution was applied in the Bentley field located in the UK sector of the North Sea in block 9/3b, on which final appraisal well 9/3b-6Z was flow tested in December 2010.The technical challenges included a short weather window, maintaining fluid mobility through the surface-testing equipment, oil and gas separation for metering, obtaining accurate flow measurements, and designing the most appropriate ESP system. A combination of technologies-dual-energy gamma ray venturi multiphase flowmeter, real-time monitoring, and a novel ESP completion-provided a solution that enabled successful well test execution. A multirate test reaching a final stabilized rate of 2900 bpd, with a subsequent period of pressure buildup was accomplished in less than 2.5 days with 10 to 12° API crude. A key lesson was how to obtain the quality of data that would enable reservoir engineers to extract with confidence a productivity index and perform pressure transient analysis for reservoir characterization. This success paves the way for development drilling to commence on the Bentley field at the end of 2011, but also demonstrates potential that can enable new heavy oil field developments.
Accurate well test data acquired throughout an appropriately designed test program is critical to confidently characterize a reservoir. Achieving this requires the right DST string selection or completion and stimulation designs, surface test set up / facilities, and the ability to rapidly handle dynamic changes in flow regimes. Well testing is inherently complex due to the interaction between these various elements. "Successful failures" in well testing is unfortunately not uncommon and results from each element of a test performing as per standards, but losing focus on achieving the ultimate objectives. The remote participation in operations of expertise that designed the test is becoming increasingly important in achieving test objectives, in particular in geologically complex structures, low-deliverability formations, reservoirs with high flow rate wells, or environmentally challenging conditions.Technological developments have enabled improved monitoring and controlling of advanced well testing equipment often now with multiple data acquisition systems. For increased accuracy in highly dynamic test environments, well tests are also performed using multiphase flow metering alongside separators specifically designed to increase handling and separation efficiencies with separate acquisition systems. Remotely located experts are now able to validate and evaluate data in real-time, 24/7, with flexibility to change acquisition and test programs to ensure that objectives are achieved.Real-time access and remote connectivity were provided during gas condensate testing of three North Sea wells in the Grove field. This paper describes the value of real-time services where the test program required continuous data quality assurance and rapid real-time evaluation onshore. This paper also demonstrates how real-time collaboration of personnel at multiple sites was crucial in carrying out a successful pressure transient analysis and a complete interpretation, both of which helped achieve the test program objectives within the planned test duration.
Though there are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs, there is still no simple, practical production forecasting methodology for hydraulically propped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector. The candidate selection process, including production prediction, is at an infant development stage and is additionally hampered by the lack of, or ambiguity in, the reservoir and production data. This is particularly true for the Yamburgskoe gas condensate field, where the wells are completed in a series of medium- and low-permeability reservoirs. Some wells cannot maintain stable production rates and have either been shut-in or are on intermittent production. Factors may include low reservoir quality, reservoir pressure, and specific production conditions. A reliable methodology for selection of candidate wells for stimulation treatments was clearly needed. This paper describes the comprehensive methodology derived from integrated analysis of the fracturing treatments performed between 2003 and 2005 in the Yamburgskoe gas-condensate field. The analysis revealed a series of correlations and elaborated an engineering approach that reduced the assumptions in the estimation of hydraulic fracturing efficiency, particularly for the wells that were completed but were unable to maintain stable production. Although the certainty of the final, stabilized production rate remains a challenge for the production and stimulation engineer, recent production results showed that hydraulic propped fracturing can bring many wells to economical production. Introduction Candidate selection and accurate post-fracturing productivity prediction was a main challenge in the recent stimulation campaigns of the Neocomian formation (Fig. 1) in the Yamburgskoe gas condensate field. This crucial process is difficult and time consuming. In this case it was further complicated because the main pool of preselected candidate wells included wells that were either never completed after drilling, or were shut-in for a long period of time; therefore no recent production history or recent measurements of reservoir pressure and other crucial parameters were available. Therefore the method envisioned had to be based on frequently available information---the openhole logs that are commonly used in the Russian oil field, i.e., the spontaneous potential, gamma-ray, neutron and resistivity, and information from common well testing. In most cases, these were the only data available in any significant quantity, and therefore a thorough analysis of the available testing practices was necessary. Also, the methods of determining reservoir pressure, fluid composition, and production prediction that have been historically applied in the field had to be compared to understand the possible discrepancies in prediction results. The range of application of the various inflow equations also had to be determined.
Well Testing for reservoir characterisation and production assessment has always been critical, especially in offshore highpressure, high-temperature (HPHT) environments. A limitation of technology available for HPHT environments in conjunction with strict safety and environmental constraints elevate the operational challenges over those associated with non-HPHT well testing.The use of a conventional test separator from well opening in gas-condensate well testing is not straight forward, especially in high pressure wells, due to slugging and rapid and continuous phase changes in the early life of the test. Concurrently, accurate flow rate measurement from well opening is crucial for well test interpretation, and estimation of total recovered well effluent. Well test interpretation of fast reservoir pressure response typically observed in HPHT conditions becomes complex, and thus the pressure change needs to be accurately measured at a high scanning rate by downhole memory gauges. Furthermore, and throughout the duration of the well test, personnel safety and environmental responsibility are paramount, thus emphasizing the importance of up-front planning and application of advanced technology, qualified to maximum anticipated conditions, to eliminate and mitigate the associated risks of HPHT well testing. This paper describes the unique combination of technology, selection, and qualification process of downhole equipment for long duration and anticipated operation conditions that enabled successful well testing on the high profile HPHT Jackdaw gascondensate field situated in Block 30/2 & 3, the North Sea. The paper also describes the benefits of using a new generation of well test separator, which is equipped with coriolis meters and an adjustable weir plate for optimum separation efficiency in HPHT environments. It also demonstrates how real-time collaboration of experts at multiple sites via a real-time data delivery system was crucial in acquiring high quality data and providing concurrent feedback to ensure safe and trouble-free well testing operations.
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.