Sampling With Multiphase Flowmeter in Northern Siberia—Condensate Field Experience and Sensitivities (Russian)
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Surface welltesting of Gas-Condensate with multiphase flowmeters is still considered a challenge for production metering. Traditional means of well testing have been deployed for years and used consistently for reservoir and production management. However, it can be difficult to compare data sets obtained with different measurement devices.Multiphase flow meters have been proved for multiphase production metering by many operation companies worldwide. However, in artic environmental conditions like those of Yamburgskoe gas-condensate field, with low ambient temperature and production rate regulation restrictions, this process had to be revalidated and the operational capabilities confirmed with all of the logistical challenge of this environment. A number of recommendations to prevent and mitigate the impact of the hydrate and document major benefits of multiphase well testing are based on the accumulated operational experience from the operations of various multiphase flowmeters in the area.Most of the gas condensate wells in the Yamburgskoe gas-condensate field are flowing with liquid unloading issues in a slug flow regime that can be observed and monitored accurately with multiphase flow meters. The importance of slug flow regime identification relates to the selection of stable flow intervals for surface sampling and further recombination factor determination. This information is also extremely important for well completion design. There is good agreement between the slug frequencies obtained with nodal simulations and the actual dynamic measurements from the meter -an impossible task for conventional measurements based on separator or batch processing of the liquid.Surface well testing to control changes of reservoir parameters, PVT composition, and production back-allocation performance is one of the key parts of gas-condensate field development in Russia. A number of multiphase welltesting operations have been successfully performed recently that show acceptable performance capability and the benefits of this methodology compared to the parallel production measurement with a traditional gas separator. This novel comparison and qualification process of multiphase flow meters also provides a better understanding of the aptitude of conventional means to collect rate in the case of wet gas wells in Northern Siberia.
Surface welltesting of Gas-Condensate with multiphase flowmeters is still considered a challenge for production metering. Traditional means of well testing have been deployed for years and used consistently for reservoir and production management. However, it can be difficult to compare data sets obtained with different measurement devices.Multiphase flow meters have been proved for multiphase production metering by many operation companies worldwide. However, in artic environmental conditions like those of Yamburgskoe gas-condensate field, with low ambient temperature and production rate regulation restrictions, this process had to be revalidated and the operational capabilities confirmed with all of the logistical challenge of this environment. A number of recommendations to prevent and mitigate the impact of the hydrate and document major benefits of multiphase well testing are based on the accumulated operational experience from the operations of various multiphase flowmeters in the area.Most of the gas condensate wells in the Yamburgskoe gas-condensate field are flowing with liquid unloading issues in a slug flow regime that can be observed and monitored accurately with multiphase flow meters. The importance of slug flow regime identification relates to the selection of stable flow intervals for surface sampling and further recombination factor determination. This information is also extremely important for well completion design. There is good agreement between the slug frequencies obtained with nodal simulations and the actual dynamic measurements from the meter -an impossible task for conventional measurements based on separator or batch processing of the liquid.Surface well testing to control changes of reservoir parameters, PVT composition, and production back-allocation performance is one of the key parts of gas-condensate field development in Russia. A number of multiphase welltesting operations have been successfully performed recently that show acceptable performance capability and the benefits of this methodology compared to the parallel production measurement with a traditional gas separator. This novel comparison and qualification process of multiphase flow meters also provides a better understanding of the aptitude of conventional means to collect rate in the case of wet gas wells in Northern Siberia.
The production focus has shifted from the easy-to-access, shallow, gas-bearing deposits in the Cenomanian and Valanginian of the Urengoyskoye Field to the deeper, tight, gas-condensate formations in the Achimov. Several different operators have started to develop the Achimov formation with different development strategies on over eleven license blocks; however, with the common objective to maximize liquid and gas production from their license. Based on a couple of pilot projects with extensive testing, a unified development plan over the entire Achimov formation had been devised before the development start-up to guarantee hydro-carbon recovery and guide the operators through the development. Due to the enormous challenges encountered in the Achimov formation such as high pressure, low formation quality and deviated well stability challenges, the initial unified development plan foresaw the drilling of simple production pattern with a large amount of vertical wells. However, since the instigation of the unified strategy, the technology has advanced to overcome most of the challenges encountered in the Achimov formation with the potential of improving the sub-optimal, original development plan. This paper discusses the general challenges of the Achimov development from well construction, production operations to reservoir management encountered by the various operators and attempts to define integrated solutions chains to overcome those. The operational and financial impact of the various technologies of the solution chains is defined and a possible roadmap for field development is devised. Several different operators have started to develop the Achimov formation with different development strategies on over eleven license blocks.
In-Line Measurement of H2S Content in Flow with a Multiphase Flow Meter - Case Study in a Giant Field under Sour Gas Re-Injection
A new approach in advanced multiphase metering methodology designed for use in sour fields, quantifying H2S content in flow and properly accounting for it in the different phase rate measurements is presented. Flow metering in sour fields is challenging due to the need for containment of produced fluids and the effect of fluid properties in the interpretation of the measurements. The addition of H2S measurement provides additional information for production and reservoir monitoring and also yields improvements in flow metering, accounting for variations in fluid properties used for multi-phase calculation. Multiphase Flow Meters (MPFM) utilizing multi-energy gamma-ray fraction measurements are based on the ability of oil, gas, and water to absorb gamma rays of two different wavelengths. Adding an extra measurement at a third level of energy and leveraging the large contrast between the attenuation of sulfur and that of hydrocarbon and water components makes it possible to determine the mass fraction of H2S as an additional output. This technique was applied in Tengiz field, Kazakhstan, characterized by a high H2S content. In order to maintain reservoir pressure, improve recovery and utilize produced associated gas, a sour gas miscible flood pilot was started in 2007. The monitoring of compositional variation in producers is critical in the understanding of solvent (sour gas) distribution and thus in managing production-injection patterns to optimize plant throughput. Early field trials of the method were made comparing metered H2S content with surface PVT samples, confirming the accuracy of the methodology. The technology was then implemented systematically but strategically across the field. The in-line H2S measurement with automatic updates for variation in fluid properties was applied in two distinct areas: within the sour gas injection pilot area, where solvent levels vary, and outside the area where hydrocarbon composition is known to be homogeneous and constant. Long and short term tests with multi-rate well tests were conducted. Full datasets were collected from the MPFM to evaluate measurement stability and representativity under different flowing conditions and compared to results obtained without accounting for compositional changes. The results show a stable, accurate and continuous measurement of H2S content in produced fluid and an enhanced measurements of water, oil and gas rates comparable with PVT results. The in-line H2S measurement based on multi-energy gamma ray measurements is the only continuous H2S measurement technology available in multiphase flow conditions. It can be retrofitted to existing MPFMs, allowing to get additional parameter and enhanced stability of flow rate measurements where properties of produced fluid vary continuously. This paper will begin with a presentation of the theory, formulation and validation of the in-line H2S measurement and then go on to present a case history of the application in the Tengiz field, Kazakhstan for Tengizchevroil (TCO).
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