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Abstract An innovative technology for determining the water cut in well products (without preliminary separation into liquid and gas fractions) uses the results of electrical impedance measurements and its dependence on the alternating current frequency. Water cut meter's sensor includes measuring and current electrodes, between which there is a well's multiphase flow. Imaginary and real components of the impedance quantitatively describe the component composition of the studied oil and gas-water mixtures. In this process, machine learning methods and developed algorithms for features extraction are used. Depending on the type of emulsion, two independent sensors are used in the oil pipeline, one of which measures in a direct emulsion, the other in an inverse emulsion. Tests of the described water cut meter on flow loops in the Russian Federation and in the Netherlands, as well as studies of well flows in oil production facilities in the Russian Federation and the Kingdom of Saudi Arabia, have shown high measurement accuracy in the full range of water cut, with high gas content, as well as at high salinity and in a wide range of flow rates. To do so, modern methods of data classification based on neural networks and regression modeling implemented using machine learning are employed. It was found that the flow rates of liquid and gas do not affect the results of measuring the water cut due to the high frequency of the impedance measurements - up to 100 thousand measurements per second. Use of in-line multiphase water cut meter makes it possible to apply intelligent methods of processing field information and accumulate statistical data for each well, as a big data element for predicting and modeling in-situ processes. It will also allow to introduce promising production processes aimed at increasing oil production and monitoring the baseline indicators of the well. Novelty of the presented technology: Solution of the problem of high-speed determination of water cut in a multiphase flow without preliminary separation using impedance metering. Creation of mathematical models of multiphase flow and methods for determining the type of flow and the type of emulsion. Machine learning methods and neural networks employment for high-speed analysis of flow changes. Development, successful testing and implementation of an affordable multiphase water cut meter of our own design, which has no analogs in industrial applications.
- Europe > Russia (0.68)
- Asia > Russia (0.68)
- Asia > Middle East > Saudi Arabia (0.24)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract Recently, more and more reservoir flow models are being extended to integrated ones to consider the influence of the surface network on the field development. A serious numerical problem is the handling of constraints in the form of inequalities. It is especially difficult in combination with optimization and automatic control of well and surface equipment. Traditional numerical methods solve the problem iteratively, choosing the operation modes for network elements. Sometimes solution may violate constraints or not be an optimal. The paper proposes a new flexible and relatively efficient method that allows to reliably handle constraints. The idea is to work with entire set of all possible operation modes according to constraints and control capabilities. Let's call this set an operation modes domain (OMD). The problem is solved in two stages. On the first stage (direct course) the OMD are calculated for all network elements from wells to terminal. Constraints are handled by narrowing the OMD. On the second stage (backward course) the optimal solution is chosen from OMD.
Technology for Monitoring Gas and Water Breakthrough Intervals using Chromate Desorption Systems in the Development of Fields in the Caspian Sea
Shtun, Sergey (LLC Lukoil - Niznevolzhskneft) | Senkov, Alexsandr (LLC Lukoil - Niznevolzhskneft) | Abramenko, Oleg (LLC Lukoil - Niznevolzhskneft) | Nikishin, Igor (PLC Planima Trassers) | Efimov, Evgeny (PLC Planima Trassers) | Minakhmetov, Radik (PLC Planima Trassers) | Platonov, Igor (Samara National Research University) | Nukhaev, Marat (Siberian Federal University, Institute of Automation and Electrometry SBRAS) | Kabanov, Vasilii (SIANT)
Abstract The paper presents a novel technology for determining the intervals of gas and water breakthrough in the development of fields on the Russian shelf of the Caspian Sea. The proposed technology is similar to traditional production logging and monitoring of horizontal wells using fiber optic systems. The technology aimed at determining the phase components is based on chromate desorption systems (CDS) with individual selective analytes used. CDS are installed on the lower well completion equipment (sand filters, inflow control devices, multistage hydraulic fracturing equipment and so on) and have a unique combination of pairs of oil-, water- and gas-soluble analytes for each interval. From the CDS, an analyte begins to release when in contact with a target fluid to surface with this fluid. At the wellhead, samples are taken according to a specific program, then laboratory analysis by chromatographic methods and mathematical interpretation of the composition of the inflow are performed. The paper presents an example of work when the intervals of gas outs were determined directly in the field using a micro-chromatograph.
The Use of Induction Heating in Assessing the Technical Condition and Operating Intervals in Producing Wells
Sharafutdinov, Ramil Faizyrovich (Bashkir State University) | Valiullin, Rim Abdullovich (Bashkir State University) | Kosmylin, Denis Vladimirovich (Bashkir State University) | Ramazanov, Ayrat Shaikhullinovich (Bashkir State University) | Fedotov, Vladimir Yakovlevich (Bashkir State University) | Bajenov, Vladimir Vladimirovich (JSC TNG group) | Imaev, Alik Islamgaleevich (JSC TNG group)
Abstract The paper considers two approaches based on the use of an induction heater: the first is a "large thermal anemometer", in which the casing is heated by induction action and the problem of determining column flows, determining the flow rate and the inflow profile is solved by analyzing the formation of thermal labels (Valiullin et al., 2001, Valiullin et al., 2002), the second is a "small radial-azimuth thermal anemometer - small thermal anemometer", where an induction heater is used to heat the element of the thermal anemometer. In the second case, the problem of estimating the flow direction and estimating the flow rate is solved. For the first approach, "large thermal anemometer", the results of theoretical and experimental studies of the temperature field distribution in a physical model as close as possible to the design of a real oil well, with induction heating of the column taking into account the column flow of liquid. The influence of forced convection on the readings of temperature sensors with different locations in the well (pressed against the inner wall of the column, along the axis of the device) is studied. The advantages of the azimuthal location of temperature sensors when measuring temperature anomalies of the column motion of a liquid are shown. It is established that with the help of an azimuthally distributed temperature probe, it is possible to determine the column flow "from above" when measuring above and below the heating point of the inductor. The optimal time intervals for measuring the temperature at which the allocation of channels for the column movement of the liquid is most effective are determined. For the second approach, "small thermal anemometer", the design features of a borehole thermoconductive indicator of the inflow of indirect heating, which is heated using an induction heater, are considered. Using an induction heater, a uniform heating of the housing of the borehole thermoconductive inflow indicator is achieved. Due to the developed design, the sensor is able to detect the presence of a liquid flow directed perpendicular to the body, and determine the direction of this flow. The "large thermal anemometer" technology has been tested, which has shown its effectiveness and prospects for using it to determine backwater flows (column circulation), but there are still questions related to assessing the effect of thermal convection on the recorded temperature and the possibility of diagnosing the column circulation channel (Valiullin et al., 2017). The article (Valiullin et al., 2008) describes the developed equipment of the "active thermometry" method for conducting geophysical studies of wells, while the classical location of temperature sensors along the axis of the device is used in the borehole probe, which does not make it possible to determine the channels of the circulation channels. The sensors located in this way are more susceptible to the influence of thermal convection, while the change in the velocity and composition of the fluid can be estimated as the presence of circulation channel. In this regard, work was carried out to reduce the influence of convection, the design of the temperature probe was developed, which allows minimizing the influence of thermal convection and increasing the efficiency of the allocation of circulation channel. Thermoanemometers, better known as thermoanemometer sensors (borehole thermoconductive inflow indicator), have been widely used in field geophysics (Zhuvagin et al., 1973). The traditional sensor of a thermal anemometer, with all its advantages, is not without disadvantages, and one of these is the inability to unambiguously determine the presence and direction of the fluid flow directed perpendicular to its body. The solution of this problem would allow, along with the known solved problems, to increase the information content of the thermoanemometer sensor, namely, in terms of detecting the leakiness of the column, evaluating the operating intervals at low debits, the flow direction. This problem is solved in this work on the basis of the use of an indirect induction heater.
Sustained Annulus Pressure Diagnostics in Offshore Wells by Multisensory Spectral Acoustics
Shtun, Sergei (LUKOIL Nizhnevolzhskneft) | Senkov, Alexander (LUKOIL Nizhnevolzhskneft) | Abramenko, Oleg (LUKOIL Nizhnevolzhskneft) | Rakitin, Mickhail (LUKOIL Nizhnevolzhskneft) | Nagimov, Vener (TGT Oilfield Services) | Trusov, Alexander (TGT Oilfield Services) | Frolov, Alexander (SONOGRAM)
Abstract The monitoring of sustainable annulus pressure (SAP) in offshore wells plays an important role in the development of an oil reservoir with a massive gas cap. The method of spectral noise logging and high-precision temperature logging used to identify SAP source presented in work (Shtun 2020) proved to be good in determining the intervals of gas movement, however, the method is limited in answers. The most significant limitation of the spectral noise logging method is associated with the impossibility based on power spectrum to distinguish the zones of gas flow in the annular space and gas inflow zones from reservoir contributing SAP. This information is critical for proper workover planning to eliminate SAP. This limitation relates to the fact that the amplitude and frequency of the resulting signal depend on not only the aperture of space fluid flow through and depend on the turbulence of the fluid flow. The paper describes a novel technology of multisensory passive acoustics of radial location that is designed to differentiate far and near acoustic sources in wells to accurately define the sources of SAP. The results of laboratory and field cases in offshore oil wells were presented in this paper as well as the comparison between single sensor spectral noise logging and multisensory passive acoustics of radial location answers was given at the end of the paper based on real case studies. As shown in the paper the described technology provides a more accurate determination of the source of SAP and the geometry of fluid movement in the near-wellbore zone.
- Europe > Russia > Southern Federal District > Astrakhan Oblast > North Caspian Sea > Middle Caspian Basin > Mangyshlak-Ustyurt Basin > Yuri Korchagin Field (0.99)
- Europe > Russia > Volga Federal District > Volga Basin (0.89)
- Africa > Tanzania > Indian Ocean > Nyuni Island > Ruvuma Basin > Rufiji River Delta > Nyuni Block > Neocomian Sandstones Formation > Nyuni-2 Well (0.89)
Efficiency Survey of a Drainage Wellbore and Well Placement in Gas Fields
Penigin, Artem Vitalevich (Gazpromneft Science&Technology Center) | Sergeev, Evgeniy Ivanovich (Gazpromneft Science&Technology Center) | Varavva, Artem Igorevich (Gazpromneft Science&Technology Center) | Yamaletdinov, Airat Flurovich (Gazpromneft Science&Technology Center)
Abstract The paper describes the assessment process of methods for the construction and operation of gas wells with a large water-gas ratio. One of the ways to tackle the issue of poor performance of high WGR wells is to drill a drainage wellbore with an ESP to lift accumulating water. In addition, various configurations of well placement through gas-bearing and water-bearing reservoirs have been considered. To evaluate the efficiency of a drainage wellbore with an ESP installed for lifting water that comes from the main, productive, wellbore, industry-recognized non-stationary dynamic multiphase flow simulator was used, as well as a more refined tool, such as the physical simulator based on the finite volume method (computational fluid dynamics, CFD). A non-stationary dynamic simulator was also used to assess the impact of well placement through gas- and water-bearings reservoirs. Well data, fluid data, physical parameters were entered into the models and, by varying the input parameters, dependencies and results were obtained, allowing to draw a conclusion about the efficiency of each method, as well as about the software capabilities and limitations. The applicability and technical efficiency of an additional drainage borehole with an ESP tto ensure stable operation / high productivity of the well strongly depend on the value of the water-gas ratio, the higher it is, the lower the efficiency of the method. In addition, efficiency also decreases with increasing gas rate. To assess the correctness of the calculation made with dynamic multiphase flow simulator, which is the industry standard, a verification calculation was also carried out on a physical simulator using the finite volume method, which shows the same trends, but with different absolute values. It also made it possible to assess the influence of the geometry factor on the distribution of flows, which could not be done by the non-stationary multiphase flow simulator. Apart from this, it was concluded that the location of a water-bearing reservoir in the last lower part of the wellbore is preferable, since then the impact on production is less than when it is located above the gas-bearing interval. Changing the well layout to a U-shaped one affects the dynamics of its operation insignificantly. The study helps to answer the question about the efficiency of using a borehole with an ESP and about the degree of influence of drilling through gas- and water-bearing reservoirs using the example of a real field, as well as it presents the method of conducting such an assessment for other fields.
A Set of Solutions to Reduce the Water Cut in Well Production
Isaev, Anatoliy Andreevich (Sheshmaoil Management company LLC) | Takhautdinov, Rustem Shafagatovich (Sheshmaoil Management company LLC) | Malykhin, Vladimir Ivanovich (Sheshmaoil Management company LLC) | Sharifullin, Almaz Amirzyanovich (Sheshmaoil Management company LLC)
Abstract This paper presents a set of activities to reduce water cut and develop a technical solution to measure water cut: measurement of watercut, flow rates and gas-oil ratio of a well output using a mobile unit. tracer tests and conformance control operations - watercut of reacting wells within Bashkirian stage decreased by 16,6% after those operations were performed. water flow control, flow deviation and remedying production casing damages made it possible to reduce extraction of produced water and, accordingly, the cost of oil production. development of Liquid Phase Separation Device enabled alternate delivery of oil and water to the intake of downhole pump.
- South America > Colombia > T Formation (0.99)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
The Role of Emulsification and Interfacial Tension Ift For the Enhanced Oil Recovery Eor in Surfactant Flooding
Li, Xiaoxiao (China University of Petroleum, Beijing) | Yue, Xiang'an (China University of Petroleum, Beijing) | Zou, Jirui (China University of Petroleum, Beijing) | Zhang, Lijuan (China University of Petroleum, Beijing) | Tang, Kang (China University of Petroleum, Beijing)
Abstract In this study, a visualized physical model of artificial oil film was firstly designed to investigate the oil film displacement mechanisms. Numerous comparative experiments were conducted to explore the detachment mechanisms of oil film and oil recovery performances in different fluid mediums with flow rate. In addition, the of influencing factors of oil film were comprehensively evaluated, which mainly includes: flow rate, surfactant behaviors, and crude oil viscosity. The results show that, (1) regardless of the viscosity of crude oil, flow rate presents a limited contribution to the detachment of oil film and the maximum of ultimate oil film displacement efficiency is only approximately 10%; (2) surfactant flooding has a synergistic effect on the oil film displacement on two aspects of interfacial tension (ITF) reduction and emulsifying capacity. Giving the most outstanding performance for two oil samples in all runs, IFT reduction of ultra-low value is not the only decisive factor affecting oil film displacement efficiency, but the emulsifying capability plays the key role to the detachment of oil film due to effect of emulsifying and dispersing on oil film; (3) the increasing flow rate of surfactant flooding is able to enhance the detachment of oil film but has an objective effect on the final oil film displacement efficiency; (4) flow rate have the much influence on the detachment of oil film, but the most easily controlled factor is the surfactant property. The finding provides basis for oil film detachment and surfactant selection EOR application.
Localisation and Recovery Planning of the Remaining Hydrocarbon Reserves
Aslanyan, Artur Mihailovich (Nafta College) | Popov, Arkadii Yurievich (Gazpromneft STC) | Zhdanov, Ivan Aleksandrovich (Gazpromneft STC) | Pakhomov, Eugeny Sergeevich (Gazpromneft STC) | Ibryaev, Nikolay Petrovich (Gazpromneft-Noyabrskneftegas JSC) | Kuznetsov, Maksim Aleksandrovich (Gazpromneft-Noyabrskneftegas JSC) | Krichevsky, Vladimir Markovich (Sofoil) | Garnyshev, Marat Yurievich (Sofoil) | Guss, Rodion Vladimirovich (Sofoil)
Abstract The paper presents the results of a study project of 60+ well block of the large (> 1,000 wells) mature (30 year old) oilfield in Western Siberia with objective to localise and characterize residual recoverable reserves and propose the optimal economic scenario for further depletion. Low permeability, heterogeneous reserve structure along the cross-section, numerous induced hydraulic fractures in producing wells and numerous spontaneous fractures in injecting wells with dynamic behavior, aggravated by numerous behind-the-casing crossflows in almost every well have resulted in a very complex conditions of remaining reserves. The conventional methods of production analysis and surveillance (well testing and production logging) do not provide a consistent picture of the current distribution and conditions of the remaining reserves and required a deeper and more complex analysis. Development Opportunities Management workflow was chosen for this particular holistic study, which includes a set of interconnected studies, field surveillance, geological and flow modelling and culminated in field development planning based on the digital asset twin. (Ganiev, B., 2021) Digital asset twin was constructed based on results of this workflow with a full-range economical model, flow simulation over the thoroughly calibrated fine-grid 3D dynamic model and production complication model (dynamic behavior of the fractures and behind-casing channeling). The 3D model has been calibrated on results of the cross-well pressure-pulse surveillance, reservoir-oriented production logging and was validated by the results of the drilling of the transition wells. The digital asset twin was used to find the optimal investment scenario based on multivariate calculations with the help of digital assistants. Due to simplicity of the user interface and client-server design, the digital twin was made available for various corporate engineers and managers without any modelling skills to play around with their own ideas on possible production/investment scenarios which gave another level of validation of the ultimate field development plan. All activities carried out within the digital twin automatically generate a complete package of investment metrics (NPV, PI, IRR, MIRR, Cash Flow and many correlation graphs) to assess the economic efficiency of each package and select the most appropriate solution for further ultimate choice. The approved scenario was based around drilling 6 producing side-tracks in specific locations/trajectories, performing workovers on specific offset injectors and re-scheduling of the production/injection rates in all block wells. The results of the field development's activities implementation will be the subject of a future publication.
- Europe (0.93)
- Asia > Middle East (0.67)
- North America > United States > Texas (0.34)
- North America > Canada > Alberta (0.34)
- North America > Canada > Alberta > High Level Field > Amax Andex Et Al Highl 16-13-111-20 Well (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 186 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 115 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- (14 more...)
Abstract The complex interbedded heterogeneous reservoirs of the Severo-Komsomolskoye field are developed by horizontal wells in which, as part of the pilot project's scope, autonomous inflow control devices (AICD) are installed to prevent early coning and gas breakthroughs in long horizontal sections and reduce sand production, which is a problem aggravated by an extremely low mechanical strength of the terrigenous deposits occurring in the Pokur formation of the Cenomanian stage in this area. The zones produced through AICDs are separated by swell packers. The issue of AICD effectiveness is discussed in the publications by Solovyev (2019), Shestov (2015), Byakov (2019) and some others. One of the methods used for monitoring horizontal sections with AICDs is production logging (PLT). However, due to the complexity of logging objectives, the use of conventional logging techniques makes the PLT unfeasible, considering the costs of preparing and carrying out the downhole operations. This paper provides some case studies of the Through-Barrier Diagnostics application, including passive spectral acoustics (spectral acoustic logging) and thermohydrodynamic modelling for the purpose of effective estimation of reservoir flows behind the liner with AICDs installed and well integrity diagnostics. As a result of the performed diagnostics, the well completion strategy was updated and optimised according to the log interpretation results, and one well intervention involving a cement squeeze with a straddle-packer assembly was carried out.
- North America > United States > Wyoming > Rim Field (0.99)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > West Siberian Basin > Central Basin > North Komsomolskoye Field (0.98)