Overcoming High Watercut And High Free gas Content On ESP Well Using VSD Field Study

2018 ◽  
Author(s):  
Bastian Wismana
Keyword(s):  
Field Study ◽  
Gas Content ◽  
Free Gas

The Gas Content Characteristics of Nanopores Developed in a Normal Pressure Shale Gas Reservoir in Southeast Chongqing, Sichuan Basin, China

2021 ◽  
Vol 21 (1) ◽  
pp. 698-706
Author(s):  
Fangwen Chen ◽  
Qiang Zheng ◽  
Hongqin Zhao ◽  
Xue Ding ◽  
Yiwen Ju ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Shale Gas ◽  
Normal Pressure ◽  
Gas Content ◽  
Organic Carbon Content ◽  
Gas Reservoir ◽  
Free Gas ◽  
Shale Gas Reservoir ◽  
Adsorbed Gas ◽  
Longmaxi Shale

To evaluate the gas content characteristics of nanopores developed in a normal pressure shale gas reservoir, the Py1 well in southeast Chongqing was selected as a case study. A series of experiments was performed to analyze the total organic carbon content, porosity and gas content using core material samples of the Longmaxi Shale from the Py1 well. The results show that the adsorbed gas and free gas content in the nanopores developed in the Py1 well in the normal pressure shale gas reservoir range from 0.46–2.24 m3/t and 0.27–0.83 m3/t, with average values of 1.38 m3/t and 0.50 m3/t, respectively. The adsorbed gas is dominant in the shale gas reservoir, accounting for 53.05–88.23% of the total gas with an average value of 71.43%. The Gas Research Institute (GRI) porosity and adsorbed gas content increase with increasing total organic carbon content. The adsorbed gas and free gas contents both increase with increasing porosity value, and the rate of increase in the adsorbed gas content with porosity is larger than that of free gas. Compared with the other five shale reservoirs in America, the Lower Silurian Longmaxi Shale in the Py1 well developed nanopores but without overpressure, which is not favorable for shale gas enrichment.

scholarly journals Geological models and controlling factors of gas content in marine–terrigenous shale in the Southern Qinshui Basin, China

2018 ◽  
Vol 37 (1) ◽  
pp. 375-393 ◽  
Author(s):  
Xiaowei Hou ◽  
Yanming Zhu ◽  
Zhenfei Jiang ◽  
Haitao Gao
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Carbon Content ◽  
Adsorption Capacity ◽  
Total Organic Carbon Content ◽  
Gas Content ◽  
Organic Carbon Content ◽  
Isothermal Adsorption ◽  
Free Gas ◽  
Adsorbed Gas

Geological prediction models for gas content in marine–terrigenous shale under the effects of reservoir characteristics and in situ geological conditions, were established using methane isothermal adsorption, high temperature/pressure methane isothermal adsorption, total organic carbon, X-ray diffraction, mercury porosimetry, porosity in net confining stress, and field desorption methods. Results indicated that the adsorption capacity of marine–terrigenous shale has a linearly positive correlation with total organic carbon content and maturity. Clay and quartz minerals are the two main components of inorganic minerals in marine–terrigenous shale, with an average content of 54.3% and 36.9%, respectively. Adsorption capacity of marine–terrigenous shale is slightly positive correlated with clay content, while it exponentially decreases with increasing quartz content. The effects of in situ temperature and reservoir pressure on adsorption capacity in marine–terrigenous shale are also significant. The adsorption capacity of marine–terrigenous shale shows a clear decreasing trend as temperature increases, while it increases with increasing reservoir pressure. The porosity of marine–terrigenous shale is characterized by highly stress-sensitive, decreasing exponentially with increasing effective stress, which results in a more complex occurrence of free gas in deep shale reservoirs. In addition, gas saturation for the shale samples was calculated based on the results of field desorption, after which geological prediction models of total gas, adsorbed gas, and free gas were established while considering the coupled effects. Adsorbed gas, free gas, and total gas content all initially increase as burial depth increases, and then eventually decrease. Adsorbed gas content and free gas content have a positive correlation with total organic carbon content and porosity, indicating that the total gas content at different burial depths is mainly controlled by the total organic carbon content and porosity.

Experimental Studies of Liquid Holdup in the Impeller of Electric Submersible Pump

2021 ◽  
Author(s):  
Kirill Goridko ◽  
Vladimir Verbitsky ◽  
Evgeny Nikonov ◽  
Max Nikolaev
Keyword(s):  
Volume Content ◽  
Slip Velocity ◽  
Volume Fraction ◽  
Experimental Studies ◽  
Performance Degradation ◽  
Gas Content ◽  
Liquid Volume ◽  
Liquid Holdup ◽  
Free Gas ◽  
Special Stand

Abstract Artificial lift of oil by electric submersible pumps (ESP) is often complicated by free gas in production. Free gas content in production leads to ESP performance degradation in rate and head. Gas slip in the ESP impeller is one of the reasons of ESP performance degradation. Thus, the goal of the work is to determine the gas slip coefficient i.e. liquid holdup in the ESP impeller. It is known that a gas-liquid mixture (GLM) flow characterized by a slippage effect. Gas slippage relative to the liquid determines the GLM structure (bubble, dispersed-bubble, slug, stratified or annular), as well as the difference between the GLM densities calculated by liquid holdup or liquid volume content. Special stand was designed and created to determine the liquid holdup at the Department of Oil Fields Development and Operation of Gubkin University. Liquid holdup in the impeller of the ESP was measured by the method of cutting off the flow. This paper shows the results of experimental studies of liquid holdup and gas slip velocity in the ESP impeller (ESP5-50) at a rotational speed n = 2997 rpm, at an absolute intake pressure Pin = 0.4 MPa. The dependence of the liquid holdup on liquid volume content (i.e. the dependence of the gas void fraction on gas volume fraction) was determined for the model GLM "water-air", "water-surfactant-air" with different foaming capacity. The degradation of the ESP characteristics, boundaries of surging and gas locking limits are determined taking into account liquid holdup. The dependence of gas holdup was experimentally obtained over the entire range of ESP operation (from 0.5∙Qopt to Qmax). A comparison of the obtained correlation with existing models is presented too. A new correlation for predicting liquid holdup in the ESP impeller for the low-rate wells operation is obtained. A new approach to determining the liquid holdup and consequently gas slip velocity in the ESP impeller is proposed.

Paper 2: The Velocity of Water Hammer Waves

1965 ◽  
Vol 180 (5) ◽  
pp. 12-20 ◽  
Author(s):  
I. S. Pearsall
Keyword(s):  
High Pressures ◽  
Water Hammer ◽  
Acoustic Velocity ◽  
Gas Content ◽  
Pressure Waves ◽  
Free Gas ◽  
Pumping Stations ◽  
Flow Changes ◽  
Very High ◽  
Good Agreement

Sudden flow changes in a pipeline cause water hammer waves to be transmitted up the pipe. The magnitude of these pressure waves is directly proportioned to the acoustic velocity. The value of the acoustic velocity depends on the bulk modulus or compressibility of the liquid. It is thus affected by pressure, temperature and gas content of the liquid, as well as by the elasticity of the pipe. For water, considerable data are available on the variation of acoustic velocity with temperature and pressure. These are summarized and it is shown that, whereas temperature causes changes of the order of 1 per cent per 5 degC, the variation due to pressure is negligible except at very high pressures. The presence of free gas causes a considerable increase in compressibility, and it is shown that even as little as 1 part of air in 104 parts of water by volume causes a 50 per cent reduction in acoustic velocity. The damping of the pressure waves, which has an overall beneficial effect, is also greatly increased by the presence of free gas, and data are given on these effects. Solids in liquid have a similar but less drastic influence. Experimental results are given of some tests on two sewage pumping stations in which good agreement was obtained between theory and experiment. The elasticity of the pipe also affects the acoustic velocity and a summary is given of the data available for steel, concrete, and rock-lined tunnels, with different types of pipe fixing.

scholarly journals Shale Gas Content Calculation of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China

2017 ◽  
Author(s):  
Jiao Su ◽  
Yingchu Shen ◽  
Bo Liu ◽  
Jin Hao
Keyword(s):  
Shale Gas ◽  
Calculation Method ◽  
Indirect Method ◽  
Ordos Basin ◽  
Gas Content ◽  
Dissolved Gas ◽  
Yanchang Formation ◽  
Free Gas ◽  
Shale Reservoirs ◽  
Method Show

Shale gas content is the key parameter for shale gas potential evaluation and favorable area prediction. Therefore, it is very important to determine shale gas content accurately. Generally, we use the USBM method for coal reservoirs to calculate gas content of shale reservoirs. However, shale reservoirs are different from coal reservoirs in depth, pressure, core collection, etc. This method would inevitably cause problems. In order to make the USBM method more suitable for shale reservoir, an improved USBM method is put forward on the basis of systematic analysis of core pressure history and temperature history during shale gas desorption. The improved USBM method modifies the calculation method of the lost time, and determines the temperature balance time of water heating. In addition, we give the calculation method of adsorption gas content and free gas content, especially the new method of calculating the oil dissolved gas content and water dissolved gas content which are easily neglected. We used the direct method (USBM and the improved USBM) and the indirect method (adsorption gas, free gas and dissolved gas) to calculate the shale gas content of 16 shale samples of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China. The results of the improved USBM method show that the total shale gas content is high, with an average of 3.97 m3/t, and the lost shale gas content is the largest proportion with an average of 62%. The total shale gas content calculated by the improved USBM method is greater than that of the USBM method. The results of the indirect method show that the total shale gas content is large, with an average of 4.11 m3/t, and the adsorption shale gas content is the largest proportion with an average of 71%.  The oil dissolved shale gas content which should be taken attention accounts for about 7.8%. The relative error between the improved USBM method and indirect method is much smaller than that between USBM method and indirect method, which verifies the accuracy of the improved USBM method.

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