Shimizu, Tsutomu (National Institute of Advanced Industrial Science and Technology) | Yamamoto, Yoshitaka (National Institute of Advanced Industrial Science and Technology) | Tenma, Norio (National Institute of Advanced Industrial Science and Technology)
The local two-phase gas/liquid flow behavior at a high velocity gradient is essential for managing gassy wells. In this study, the methane/water bubbly flows passing through a perforated pipe were characterized in a 10.4-m flow loop in which the pressure was varied up to 5.5 MPa at 291 K. To characterize the two-phase flow behavior at the bore, we obtained the bubble sizes from high-speed photographs and digital image analysis. As the flow velocity and/or pressure increased, the flow patterns shifted from bubbling to jetting, suggesting that the local two-phase flow pattern can control the bubble size in flowlines.
Multiphase flow control in wells and pipelines is crucial in the oil and gas industries. The most important components affecting the production efficiency, cost, and safety of gassy wells are the gas/liquid separators and multiphase flow pumps. For instance, the gas/liquid separators reduce the void fraction at the pump intake, thereby minimizing the pump surging (Hua et al., 2012; Gamboa and Prado, 2011). Phase separation reduces the risk of pipe plugging through the formation of gas hydrates (Shimizu et al., 2017; Joshi et al., 2013; Sakurai et al., 2014). In gas production from offshore natural gas hydrate reservoirs, these devices must handle two-phase flows under variable pressure and void fraction in a natural-gas/seawater mixture, while stably maintaining the bottom-hole pressure below the three-phase equilibrium pressure (Cyranoski, 2013). Optimizing the performance of these devices in such situations is a necessary yet challenging task.
Bubbles formed by breakup and coalescence are of paramount importance in industrial heat and mass transport processes and are typically generated by a gas distributor (Idogawa et al., 1987; Quinn and Finch, 2012; Tsuge and Hibino, 1983) or a rotating impeller (Kracht and Finch, 2009; Minemura et al., 1998; Masui et al., 2011). Hence, bubble formation has been studied extensively for decades. However, few studies have focused on the bubble behavior under a high velocity gradient in pipelines, where bubbles assist the transmission of the gas/liquid flow mixture in practical production fields.
Li, Hao (China University of Petroleum) | Sun, Baojiang (China University of Petroleum) | Gao, Yonghai (China University of Petroleum) | Guo, Yanli (China University of Petroleum) | Zhao, Xinxin (China University of Petroleum) | Wang, Jintang (China University of Petroleum) | Wang, Jin Bo (China University of Petroleum)
The formation of hydrate membrane on the methane bubble surface could occur in the high pressure & low temperature wellbore during the shut-in period. Using an empirical drag coefficient model to investigate the laws of methane bubble with hydrate membrane rising in drilling mud is important for calculating the well control safety operation cycle time in avoiding typhoon. The drag coefficient for methane bubble with hydrate membrane rising in mud within a wellbore was experimentally investigated using a vertical, cylindrical wellbore with high pressure & low temperature. A high-speed camera was used to obtain the process of methane bubble with Methane hydrate membrane (MHM) rising under 6 MPa & 4 °C. The velocities of bubbles were measured by image processing software. The drag coefficients of different bubbles were calculated and the variation law of drag coefficient with Reynolds number was obtained. A new correlation of drag coefficient for the bubbles covered with hydrate membrane is established. The result of experiment indicated that the rising velocity of methane bubble with hydrate membrane would increase along with the increase of equivalent diameter, while drag coefficient would decrease before increase along with the increase of equivalent diameter. Due to the influence of hydrate membrane, the rising process of methane bubble covered with hydrate membrane would be significantly different from that of pure gas bubble; compared with pure gas bubble, the methane bubble of same diameter would have lower rising velocity. Through the comparison with known correlation of drag coefficient, it is believed that the existing drag coefficient correlations are not applicable to the prediction of drag coefficient of methane bubble covered with hydrate membrane. A new correlation of drag coefficient of rising methane bubble covered with hydrate is established, such correlation has scope of prediction error within ±25%. Considering the influence of hydrate membrane, a new rising velocity model for methane bubble covered with hydrate membrane is established to calculate the drag coefficient.
Moving gas show analysis from surface to downhole at the drill bit has the advantages of identifying sweet spots directly and immediately, enabling focused stimulation which can lead to improved well production and EOR, and to optimized completion, and kick detection at the bit. We have explored the use of optical spectroscopy for gas show at the drill bit. Based on our initial study we identified two potential approaches – a Raman spectroscopy-based approach where the gas concentration is measured in-situ in the dissolved state, and an absorption spectroscopy-based approach where gas is extracted out and tested. While the approach where the gas is tested in-situ would be the preferred one, the high risk involved here led us to simultaneously develop the extractive approach. Proof-of-concept experiments have been performed to down-select the most appropriate approach. We have been able to demonstrate that both methods can detect methane at the desired concentration levels down to better than 1%. It has been concluded that since dissolved methane at the required concentration can be detected using the non-extractive approach, it would be most suitable to use the Raman-based gas detection for downhole gas show at the drill bit.
Differential pressure (DP) between stages of multi-stage diffuser type centrifugal pump of an electric submersible pump (ESP), system was measured in a two-phase flow environment. The test results were used to improve existing numerical models and bubble size models for better prediction and to improve the design process. This paper details the comprehensive testing and model validation process for ESP pump stages.
Various sizes and types of ESP pump stages were tested in a high-pressure two-phase flow loop. Each stage performance was monitored using high-precision DP transducers. Test results were used to calibrate numerical simulation in two-phase flow. The correct bubble size for individual test conditions was calculated based on the test results. The bubble size calculation was crucial for good model prediction in two-phase flow. After several types and sizes of ESP stages were validated, same bubble size model could be used on other pump stages that have similar sizes and designs.
Presented in this paper are the actual gas volume fraction (GVF) handling capabilities of typical ESP stages, including the effects of flowrate, GVF, pump speed, inlet pressure, flow mixing and inlet/outlet effects.
After the lab test was complete, computational fluid dynamics (CFD) was used to investigate the hydraulic performance of the same stages and conditions tested in the lab. Simulation results were compared with test results and optimized for the correct bubble size of the secondary phase. The current bubble size model predicted very well for the lower GVF combined with large flow rate pump. The low flow pump had DP errors in excess of 10% for GVF values over 40%.
The validated numerical model can be used to improve pump modeling and enable improvements in pump design that could increase the gas-handling capabilities of pump stages of similar size and styles.
Qu, Ming (China University of Petroleum-Beijing) | Hou, Jirui (China University of Petroleum-Beijing) | Wang, Qian (China University of Petroleum-Beijing) | Su, Wei (China University of Petroleum-Beijing) | Ma, Shixi (China University of Petroleum-Beijing) | Yang, Tianyuan (China University of Petroleum-Beijing) | Li, Pengyang (China Southern Petroleum Exploration & Development Corporation) | Bai, Yu (China University of Mining and Technology-Beijing)
Tahe oilfield is one of the most important naturally fractured-vuggy carbonate oil fields in China. The characteristics of this type of reservoirs are greatly complex due to its multiple flow units: matrix, fractures and vugs. Gas flooding is a practical way of enhancing oil recovery (EOR) for fractured-vuggy carbonate reservoir. The main problems during gas flooding include the complicated oil-gas relationship and gas channeling rapidly. Gel is an effective measure to control channeling. However, ordinary gel cannot adapt to the reservoir conditions in which salinity is 220000mg/l and temperature is 120°C.
Based on Tahe oil field reservoir conditions, we develop Modified Starch Gel Foam (MSGF) which has the function of salt-tolerance and temperature-resistance on the basis of laboratory experiments. In order to study the static performance, different foam volume and half-life period were recorded by varing temperature, mineralization and pressure. We also observed microscopic morphology and bubble distribution of MSGF. To evaluate the dynamic effect, fractured-vuggy physical model was designed and fabricated to present the dynamic characteristic in fractures and vuggs media.
Experimental results show that the even distribution, similar diameters of bubbles, thick liquid membrane and high viscosity prove MSGF is stable and available in the water with the salinity of 220000mg/l and temperature of 120°C. The liquid membrane including the continuous structure formed by macromolecular gel protects the bubbles from the harmful influence of ions. After the defoaming behavior, the rest solution becomes gel again, which benefits controlling gas channeling. The item which contributes to this phenomenon is proved to be the foaming stabilizer. MSGF was able to control nitrogen mobility and channeling.
Because of the salinity and temperature tolerance, MSGF can be applied in high salinity and high temperature reservoirs, especially in fractured-vuggy carbonate reservoirs. This kind of reservoirs does not have porosity which will make it possible for normal foaming system to foam again. Besides, MSGF can achieve profile control after the foaming through secondary gelation. This study could provide a constructive guide for the fractured-vuggy carbonate reservoir to improve production performance.
Jin, Fu (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Xi, Wang (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is the unique huge ultra-tight oilfield that has not been developed by scale in the world. The high-density tight oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. ML Block whose OOIP is 178*108bbl is situated in east of the oilfield, while cluster horizontal well drilling and cold production technologies are still under research there.
Based on precise geological researches numerical simulation was carried out to optimize cold production of ultra-tight oil with foamy oil flow patterns in horizontal wells, including optimization of well placement, well spacing and horizontal section length. The near-bit geo-steering drilling technology was applied on adjacent wells to test its performance, while an experiment was conducted with PVT apparatuses to examine the effect of pressure decline rates on foamy oil flow. A long core pressure depletion test was accomplished to reveal the effect of foamy oil flow on recovery factors.
Three-dimension cluster horizontal well drilling and completion technologies shall be applied to develop ultra-tight oil reservoirs in huge loose sandstones, with the near-bit geo-steering drilling technology that controls landing points and horizontal sections in real time, keeping the bit move ahead along the lower boundary of the reservoir. Therefore, recovery rates may be dramatically improved due to the gravity drainage of ultra-tight oil. The most appropriate spacing of horizontal wells (500-600m) and horizontal section length (800-1200m) were determined to achieve the maximum recovery rate. The experiment proves that the recovery rate improves as the formation permeability increases, which means the "worm hole" contributes to heavy oil extraction. Boreholes with relatively large diameters, extensive perforated holes and slotted liners may be used to complete wells. In order to take the most advantages of the foamy oil flow mechanism high displacement ESPs shall be used with the selected thinner squeezed at the bottom, otherwise PC pumps with the thinner added at the wellhead are recommended.
Cold production technologies applied in ML Block save the overall production cost by 15.2%, improving the ultimate recovery rate by 8.6%. The foamy oil flow theory is improved, while it is the first time to integrate foamy oil flow production technologies with cluster horizontal well drilling technologies and near-bit geo-steering drilling technologies. As a result, the overall production rate of tight oil was greatly improved and the average production life of wells was extended.
Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5 m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates.
The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has its high advantage in terms of accessibility and lowered cost. Hence, attention was given to air that was mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.
Peng, Kewen (China University of Petroleum) | Li, Gensheng (China University of Petroleum) | Tian, Shouceng (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Zhang, Zhenxiang (China University of Petroleum) | Zhu, Bin (China University of Petroleum) | Nie, Xiaokang (GWDC Downhole Service Company, CNPC)
Recently high pressure water jet drilling is proposed for coalbed methane development by connecting nozzle with coiled tubing directly. However, rock breaking efficiency is still compromised because of the hydraulic energy loss when water flows through the small size coiled tubing. Cavitation is the formation of vapor in a liquid when the local pressure in the fluid is reduced to its saturated vapor pressure. The violent bubble collapse can cause severe damage to the materials caused by the high collapse pressure and temperature.
In this paper, based on bottomhole flow field analysis and nozzle survey, a convergent-divergent nozzle is optimized to trigger cavitation in water jet for multilateral drilling. A mathematical model coupling the flow field and bubble dynamics is used to predict the effective standoff distance for cavitation erosion. The classic Rayleigh-Plesset equation is solved by first order Euler finite difference at each step with a thermodynamic model. Then, laboratory experiments are conducted in a pressure vessel to validate the calculation results based on pitting analysis.
The results show that the divergent section of the nozzle is critical to generate low pressure regions inside the throat section, but not hindering bubble transportation towards the specimen outside. The optimized divergent angle is 20° and divergent length is 4 times nozzle diameter. In addition, it is demonstrated that the cavitation bubbles formed inside the nozzle can be transported to the outside flowfield against adverse pressure gradient due to its inertia. The effects of flow rate and ambient pressure on the effective standoff distance are investigated. Given certain ambient pressure, there exists a threshhold of flow rate, below which cavitation bubble can't be transported outside the nozzle. The experiment shows the maginitude of the cavitation impacts lies in the range of 800 MPa to 2700 MPa.
The present research, to our best knowledge, is the first systematic investigation on utilizing cavitation to increase erosion rate in multilateral CTD drilling. The nozzle proposed has a good compatibility with the coiled tubing. The proposed mathematical model can be used to assist engineering design and operational parameters adjustment.
Drozdov, A. N. (Gubkin Russian State University of Oil and Gas National Research University) | Drozdov, N. A. (LLC Innovative Oil and Gas Solutions) | Bunkin, N. F. (LLC Innovative Oil and Gas Solutions) | Kozlov, V. A. (LLC Innovative Oil and Gas Solutions)
The paper is devoted to the investigation of the stability of gas-liquid mixtures.
Investigations of the suppression of the coalescence of gas bubbles in a liquid at various concentrations and composition of dissolved salts were carried out on a facility containing a laser diode with a telescopic system, a glass column, a bubbler, a gas supply system, a laser reception unit with a breaker, a lens and a photodiode, an oscillograph and a computer. The value of coalescence suppression was determined from the change in the transmittance of laser radiation through a column with bubbles in the liquid. In addition, bench tests were carried out on the characteristics of ejectors and a multistage centrifugal pump when creating and pumping gas-liquid mixtures using fresh water as a liquid, as well as aqueous solutions with various concentrations of NaCl.
It has been experimentally determined that there are zones of rational salt concentrations and composition in which the coalescence of gas bubbles is suppressed due to the expression of repulsive forces between bubbles charged negatively in aqueous solutions of electrolytes. At smaller and higher concentrations coalescence suppression does not occur, and gas bubbles actively join with each other. The effect of cations and anions in aqueous solutions of various salts on the process of suppressing the coalescence of gas bubbles in a liquid is revealed.
Investigations of the produced water from Samodurovskoye field showed that its composition helps to suppress coalescence of bubbles, but the addition of a certain amount of NaCl enhances the suppression of coalescence.
When the water-gas mixture prepared by the ejector with using fresh water was pumped was pumped out on bench and the coalescence of gas bubbles was not maintained, the pressure developed by the multistage centrifugal pump decreased greatly with increasing gas content at the pump inlet. When using of NaCl aqueous solutions in the field of rational concentrations, a multistage centrifugal pump began to operate much better on a water-gas mixture. This was due to the suppression of the coalescence of gas bubbles in the liquid and the prevention of the formation of large gas caverns in the inter-blade channels of the pump.
Field studies of the pump-ejecting system for SWAG injection on Samodurovskoye field were also carried out.
The obtained results can be used for utilization of associated gas by water-gas injection, as well as in various oil production technologies, where gas-liquid mixtures move (completion, operation of wells, gathering oil, gas and water).
Sergeev, E. (Co. Ltd. BashNIPIneft) | Vinogradov, P. (Co. Ltd. BashNIPIneft) | Abutalipov, U. (Co. Ltd. BashNIPIneft) | Ivanov, A. (Co. Ltd. BashNIPIneft) | Kitabov, A. (Co. Ltd. BashNIPIneft) | Esipov, P. (Co. Ltd. BashNIPIneft)
The main task of this work was a comprehensive test of the technology of simultaneous injection of water and gas into injection wells to confirm the feasibility of this method of maintaining reservoir pressure (MRP), approbation of technical and technological solutions, taking into account further scaling and application of this type of injection at fields PJS OC Bashneft.
To study the process of simultaneous injection, an experimental test site was designed and implemented on the basis of one of the company's fields. The main elements of the technological scheme are: a fresh water pipeline, a pier with an electric centrifugal pump (ECP), a high-pressure gas pipeline that supplies associated petroleum gas (APG) from the compressor station (CS), and a mixing device that allows a fine dispersion mixture to be produced at its outlet. Regulation of the injection processes was carried out by control valves, which are installed on both lines. During the tests, the technology of the process of continuous simultaneous injection of water and gas into injection wells with a different percentage of these components was tested. On the basis of modeling, technical solutions for the preparation of a water-gas mixture with a fine-dispersed structure were developed, implemented and tested. Conditions and parameters of injection for obtaining a homogeneous fine-dispersed water-gas mixture (WGM) are determined. The behavior of the injection well in the implementation of various operating modes and with different structure of the water-gas mixture is analyzed. The main risks in the organization of this type of injection are identified and measures for their reduction are developed.
The basic principles of calculating the mixing device for obtaining a fine-dispersed water-gas mixture that improves the efficiency of the injection technology are developed. The obtained test results can be used in design and operation of reservoir pressure maintenance systems in conditions of water and gas impact.