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Tight gas reservoirs incur problems and significant damage caused by low permeability during drilling, completion, stimulation and production. They require advanced improvement techniques to achieve flow gas at optimum rates. Water blocking damage (phase Trapping/retention of fluids) is a form of mechanical formation damage mechanism, which is caus...
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Context 1
... density of fluids at high temperature was required as input. Anton Par Density meter model DMA4500 was used to measure the density of these fluids at high temperature, shown in Table 2. Three Gas-liquid systems were used in the interfacial tension measurement at high temperature and pressure conditions. ...
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Core flooding experiments were conducted with the objective of evaluating near miscible surfactant alternating CO 2 injection and the effect of surfactant concentrations on gas-oil and water displacements in porous media. The core samples were provided from a low permeability mixed wet oil reservoir at 156 °F and 1900 psia. In addition, very few st...
Citations
... This behavior can reduce the gas flow channel, and cause aqueous phase trapping (APT), which will influence the natural gas exploitation [7,8]. Usually, through quick and effective flowback to reduce the soaking time and liquid filtration distance, the APT damage can be relieved [9], and some chemical treatments for improving the flowback rate of the aqueous phase have been widely investigated [10][11][12][13][14][15]. Some equations have been proposed to evaluate the APT damage. ...
Hydraulic fracturing becomes an essential method to develop tight gas. Under high injection pressure, fracturing fluid entering into the formation will reduce the flow channel. To investigate the influence of water saturation on gas flow behavior, this study conducted the gas relative permeability with water saturation and the flow rate with the pressure gradient at different water saturations. As the two dominant tight gas-bearing intervals, the Upper Paleozoic Taiyuan and Shihezi Formations deposited in Ordos Basin were selected because they are the target layers for holding vast tight gas. Median pore radius in the Taiyuan Formation is higher than the one in the Shihezi Formation, while the most probable seepage pore radius in the Taiyuan Formation is lower than the one in the Shihezi Formation. The average irreducible water saturation is 54.4% in the Taiyuan Formation and 61.6% in the Shihezi Formation, which indicates that the Taiyuan Formation has more movable water. The average critical gas saturation is 80.4% and 69.9% in these two formations, respectively, which indicates that the Shihezi Formation has more movable gas. Both critical gas saturation and irreducible water saturation have a negative relationship with porosity as well as permeability. At the same water saturation, the threshold gradient pressure of the Taiyuan Formation is higher than the one in the Shihezi Formation, which means that water saturation has a great influence on the Taiyuan Formation. Overall, compared with the Shihezi Formation, the Taiyuan Formation has a higher median pore size and movable water saturation, but water saturation has more influence on its gas flow capacity. Our research is conducive to understanding the effect of fracturing fluid filtration on the production of natural gas from tight reservoirs.
... From Eq. 5, the relationship between capillary pressure and interfacial tension is linear where the higher is the interfacial tension, the higher is the capillary pressure and vice versa. High capillary pressure can lead to phase trapping inside a reservoir[20]. ...
Enhanced oil recovery (EOR) has been one of the favorable methods in improving oil recovery and extending the production time. One of the techniques used in enhanced oil recovery (EOR) is gas flooding, because of the gases sweeping ability to displace the oil into the production well. Unfortunately, the gas injection method causes severe gas fingering because of the higher mobility and lower viscosity and density of the gas, compared to oil, which creates uneven fluid dispersion (fingering). Thus, a stabilized surfactant foam is introduced to control the injected gas mobility. This paper aims to characterize how the blends of non-anionic and anionic surfactants could act as foam stabilizing agents and to provide a brief exploration on their ability to improve the gas flooding process. The foamability and foam stability of single and mixed surfactant were tested at ambient and elevated temperature; additionally, a salt tolerance study was performed to identify the capability of the foam to withstand real reservoir conditions. Two anionic surfactants: sodium dodecyl sulphate (SDS) and alpha olefin sulfonate (AOS) and one non-ionic surfactant, octyl phenol ethoxylate (TX-100), were used in the study. Each single surfactant was tested for its viscosity and surface tension at the air/water interface under ambient conditions and compared with the mixed surfactants. Data has shown that blending of anionic and non-ionic surfactants has contributed to lower IFT compared to the individual surfactants and to increase viscosity, which is an early indicator of good foam stabilizer for foam flooding, which may lead to oil recovery improvement. The mixture of non-ionic and anionic surfactants, particularly TX-100 and AOS, showed better foamability and foam stability at elevated temperature than the individual pure surfactants.
Formation damage is an essential part of drilling and production evaluation, which has a significant effect on well productivity and economics. Drilling fluids are significant sources of formation damage by different mechanisms. This article reviews the research works published during the past 30 years on formation damage associated with drilling fluids, including mechanical damage, chemical damage, and interaction with reservoir rock and fluids. Different filtration techniques, fines migration, and invasion models are discussed based on past studies and recent advancements. Laboratory experiments, methodology, and various aspects of evaluation are considered for further study. Despite presenting different authors’ views and experiences in this area, there is no integrated approach to evaluate formation damage caused by drilling fluids. Finally, the authors analyze the knowledge gap and conclude that a methodology must be designed to improve drilling fluids to prevent formation damage. Recent advances in the area of nanotechnology show promising alternatives for new methods to prevent formation damage.
