Experimental Simulation on Imbibition of the Residual Fracturing Fluid in Tight Sandstone Reservoirs

2019 ◽  
Vol 141 (8) ◽  
Author(s):  
Xiaoxia Ren ◽  
Aifen Li ◽  
Asadullah Memon ◽  
Shuaishi Fu ◽  
Guijuan Wang ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Experimental Simulation ◽  
Fluid Distribution ◽  
Oil Viscosity ◽  
Pore Throat ◽  
Fracturing Fluid ◽  
Tight Sandstone ◽  
The Difference ◽  
Displacement Processes

Fracturing is a fundamental technique for enhancing oil recovery of tight sandstone reservoir. The pores in tight reservoirs generally have small radii and generate tremendous capillary force; accordingly, the imbibition effect can significantly affect retention and absorption of the fracturing fluid. In this study, the imbibition behaviors of the fracturing fluid were experimentally investigated, and the effects of interfacial tension, (IFT) permeability, oil viscosity, and the salinity of the imbibition fluid were determined. In addition, combining with nuclear magnetic resonance (NMR)-based core analysis, fluid distribution, and the related variations in imbibition and displacement processes were analyzed. Finally, some key influencing factors of imbibition of the residual fracturing fluid, the difference and correlation between imbibition and displacement, as well as the contribution of imbibition to displacement were explored so as to provide optimization suggestions for guiding the application of oil-displacing fracturing fluid in exploration. Results show that imbibition recovery increased with time, but the imbibition rate gradually dropped. There exists an optimal interfacial tension that corresponds to maximum imbibition recovery. In addition, imbibition recovery increased as permeability and salinity increases and oil viscosity decreases. Furthermore, it was found that extracted oil from the movable pore throat space was almost equal to that from the irreducible pore throat space during imbibition and their contribution in the irreducible pore throat space was greater than in the movable pore throat space in the displacement process. Hence, imbibition plays a more important role during the displacement process in the reservoirs with finer porous structure than previously thought.

scholarly journals Investigation effect of wettability and heterogeneity in water flooding and on microscopic residual oil distribution in tight sandstone cores with NMR technique

Open Physics ◽  
2017 ◽  
Vol 15 (1) ◽  
pp. 544-550 ◽  
Author(s):  
Pufu Xiao ◽  
Xiaoyong Leng ◽  
Hanmin Xiao ◽  
Linghui Sun ◽  
Haiqin Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Physical Simulation ◽  
Spontaneous Imbibition ◽  
Recovery Factor ◽  
Water Flooding ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Large Pore ◽  
Oil Distribution ◽  
The Difference

AbstractIn order to explore the effect of wettability and pore throat heterogeneity on oil recovery efficiency in porous media, physical simulation experiment and nuclear magnetic resonance (NMR) measurements were conducted to investigate how crude oil residing in different sized pores are recovered by water flooding. Experimental results indicate that the recovery factor of water flooding is governed by spontaneous imbibition and also pore throat heterogeneity. It is found that intermediate wetting cores lead to the highest final recovery factor in comparison with water wet cores and weak oil wet cores, and the recovery oil difference in clay micro pore is mainly because of the wettability, the difference in medium pore and large pore is affected by pore throat heterogeneity. Water wet core has a lower recovery factor in medium and large pore due to its poor heterogeneity, in spite of the spontaneous imbibition effect is very satisfying. Intermediate wetting cores has significant result in different sized pore and throat, the difference in medium pore and large pore is affected by pore throat heterogeneity.

scholarly journals A new slick water system for hydraulic fracturing in tight reservoir to enhance imbibition oil recovery

2021 ◽  
Vol 303 ◽  
pp. 01001
Author(s):  
Yu Haiyang ◽  
Ji Wenjuan ◽  
Luo Cheng ◽  
Lu Junkai ◽  
Yan Fei ◽  
...  
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Water System ◽  
Natural Fracture ◽  
Fracturing Fluid ◽  
The Core ◽  
Ultralow Permeability

In order to give full play to the role of imbibition of capillary force and enhance oil recovery of ultralow permeability sandstone reservoir after hydraulic fracturing, the mixed water fracture technology based on functional slick water is described and successfully applied to several wells in oilfield. The core of the technology is determination of influence factors of imbibition oil recovery, the development of new functional slick water system and optimization of volume fracturing parameters. The imbibition results show that it is significant effect of interfacial tension, wetting on imbibition oil recovery. The interfacial tension decreases by an order of magnitude, the imbibition oil recovery reduces by more than 10%. The imbibition oil recovery increases with the contact angle decreasing. The emulsifying ability has no obvious effect on imbibition oil recovery. The functional slick water system considering imbibition is developed based on the solution rheology and polymer chemistry. The system has introduced the active group and temperature resistant group into the polymer molecules. The molecular weight is controlled in 1.5 million. The viscosity is greater than 2mPa·s after shearing 2h under 170s-1 and 100℃. The interfacial tension could decrease to 10-2mN/m. The contact angle decreased from 58° to 22° and the core damage rate is less than 12%. The imbibition oil recovery could reach to 43%. The fracturing process includes slick water stage and linear gel stage. 10% 100 mesh ceramists and 8% temporary plugging agents are carried into the formation by functional slick water. 40-70 mesh ceramists are carried by linear gel. The liquid volume ratio is about 4:1 and the displacement is controlled at 10-12m3/min. The sand content and fracturing fluid volumes of single stage are 80m3 and 2500 m3 respectively. Compared with conventional fracturing, due to imbibition oil recovery, there is only 25% of the fracturing fluid flowback rate when the crude oil flew out. When the oil well is in normal production, about 50% of the fracturing fluid is not returned. It is useful to maintain the formation energy and slow down the production decline. The average cumulative production of vertical wells is greater than 2800t, and the effective period is more than 2 years. This technology overcoming the problem of high horizontal stress difference and lack of natural fracture has been successfully applied in Jidong Oilfield ultralow permeability reservoir. The successful application of this technology not only helps to promote the effective use of ultralow permeability reservoirs, but also helps to further clarify the role of imbibition recovery, energy storage and oil-water replacement mechanism.

Indoor Study of Viscosity Reducer for Thickened Oil of Huancai

2012 ◽  
Vol 268-270 ◽  
pp. 547-550
Author(s):  
Qing Wang Liu ◽  
Xin Wang ◽  
Zhen Zhong Fan ◽  
Jiao Wang ◽  
Rui Gao ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Heavy Oil ◽  
High Viscosity ◽  
Oil Field ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Low Viscosity ◽  
Viscosity Reducer ◽  
Oil Water

Liaohe oil field block 58 for Huancai, the efficiency of production of thickened oil is low, and the efficiency of displacement is worse, likely to cause other issues. Researching and developing an type of Heavy Oil Viscosity Reducer for exploiting. The high viscosity of W/O emulsion changed into low viscosity O/W emulsion to facilitate recovery, enhanced oil recovery. Through the experiment determine the viscosity properties of Heavy Oil Viscosity Reducer. The oil/water interfacial tension is lower than 0.0031mN•m-1, salt-resisting is good. The efficiency of viscosity reduction is higher than 90%, and also good at 180°C.

Application of NMR Technology on Test of Movable Fluid Saturation of Tight Sandstone Gas Reservoir

2015 ◽  
Vol 1092-1093 ◽  
pp. 1361-1365
Author(s):  
Hong Xia Ming ◽  
Wei Sun ◽  
Ping Wu
Keyword(s):  
Pore Structure ◽  
Transverse Relaxation Time ◽  
Single Peak ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Fluid Saturation ◽  
Structure Heterogeneity ◽  
Spectrum Distribution ◽  
The Difference

The difference of movable fluid saturation of tight sandstone gas reservoir is researched, with transverse relaxation time (T2) distribution derived from nuclear magnetic resonance technique (NMR). This article newly calculate T2 cutoff value and elaborate the influence of pore structure on the occurrence characteristics of movable fluid. The study had revealed T2 spectrum distribution includes the following types: (1) wide and flat single peak; (2) left single peak; (3) high left peak with low right peak. Movable fluid saturation is low, with class IV and class V movable fluid mainly. Pore structure control properties and percolation ability of rock reservoir and whether oil could be driven out depends on throat parameters of interconnected pores. Movable fluid saturation is low with bigger pore throat ratio, narrower pore throat distribution and higer pore structure heterogeneity.

scholarly journals A STUDY OF THE PERFORMANCE CHARACTERISTICS OF THE OLEOPHILIC BELT “OIL SCRUBBER”

1971 ◽  
Vol 1971 (1) ◽  
pp. 309-317 ◽  
Author(s):  
J.P. Oxenham
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Outer Surface ◽  
High Viscosity ◽  
Primary Concern ◽  
Oil Viscosity ◽  
Solid Materials ◽  
Recovery System ◽  
Rate Of Absorption ◽  
The Stability

ABSTRACT Analyses and experimentation have indicated that the maximum recovery rate of an oleophilic belt oil recovery system is generally limited by the rate at which oil may be transferred to the belt surface and interior. The rate of absorption of oil by an oleophilic belt increases with increasing specific surface and permeability of the belt material increasing slick depth, decreasing oil viscosity, and decreasing interfacial tension between the oil and belt material. In operations with high viscosity oils and high belt speeds significant quantities of oil may be withdrawn on the belt's outer surface. The oil scrubber's performance is not detrimentally affected by the presence of waves, nor by the presence of solid materials, emulsions, or “rag” in limited quantities. The stability of the belt is a primary concern for operations in the presence of transverse currents.

scholarly journals Effect of Fluid/Rock Interactions on Physical Character of Tight Sandstone Reservoirs during CO2 Flooding

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Dongfeng Zhao ◽  
Dandan Yin
Keyword(s):  
Oil Recovery ◽  
Medium Size ◽  
Co2 Flooding ◽  
Production Well ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Pressure Drops ◽  
Pore Radius Distribution ◽  
Salt Crystals ◽  
Permeability Alteration

Structures of pore-throat and permeability alteration caused by precipitation and the dissolution of rock matrix are serious problems during CO2 flooding into reservoirs for enhanced oil recovery (EOR). Experiments were conducted under pressure boost and reduction conditions, which simulate CO2-brine scaling in different parts of the reservoir during CO2 flooding. And experiments on the dissolution and scaling of CO2-brine-rock were carried out. The results show that the pH of brine with CO2 under high pressure is small, and no precipitation is formed, so there is no precipitation generated near the gas injection well. Pressure drops sharply near the production well, CO2 dissolved in the formation fluid escapes in large quantities, pH increases, carbonate precipitates are generated, so inorganic scale is formed near the production well. The increase of permeability of core saturated high scale-forming ions is smaller than that of saturated no scale-forming ions brine after CO2 flooding. The accumulation and attachment of salt crystals were found in some large pores of the core with scale-forming ions water after CO2 flooding. The ratio of medium size pores decreased, while that of large and small pores increases, and the pore radius distribution differentiates toward polarization.

scholarly journals Study on the Flow Mechanism of Shale Oil with Different Injection Media

2021 ◽  
Vol 2021 ◽  
pp. 1-10
Author(s):  
Lanlan Yao ◽  
Zhengming Yang ◽  
Haibo Li ◽  
Bo Cai ◽  
Chunming He ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Bohai Bay ◽  
Shale Oil ◽  
Formation Water ◽  
Displacement Efficiency ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Oil Displacement ◽  
Oil Displacement Efficiency ◽  
Effective Development

Chinese shale oil has high recoverable resources and great development potential. However, due to the limitation of development technology, the recovery rate of shale oil is not high. In this paper, the effects of different injection media on the development of shale oil reservoirs in Dongying formation, Qikou depression, Huanghua depression, and Bohai bay basin, were studied by means of imbibition and nitrogen flooding. Combining nuclear magnetic resonance (NMR) technology with imbibition and gas displacement experiments, the mechanism of shale injected formation water, active water (surfactant), and nitrogen was reproduced. The displacement process of crude oil under different injection media and injection conditions was truly demonstrated, and the relationship between different development methods and the pore boundaries used was clarified. A theoretical basis for the effective development of shale oil was provided. At the same time, Changqing tight oil cores with similar permeability to Dagang shale oil cores were selected for comparison. The results showed that, as the imbibition time of shale samples increased, the imbibition efficiency increased. Pores with T2 < 10 ms contributed the most to imbibition efficiency, with an average contribution greater than 90%. 10 ms < T2 < 100 ms and more than 100 ms pores contributed less to imbibition efficiency. Active water can change the wettability of shale, increase its hydrophilicity, and improve the efficiency of imbibition. The imbibition recovery ratio of injected active water was 17.56% higher than that of injected formation water. Compared with tight sandstone with similar permeability, the imbibition efficiency of shale was lower. As the nitrogen displacement pressure increased, the oil displacement efficiency also increased. The higher the shale permeability was, the greater the displacement efficiency would be. T2 > 100 ms pore throat of shale contributed to the main oil displacement efficiency, with an average oil displacement efficiency contribution of 63.16%. And the relaxation interval 10 < T2 < 100 ms pore throat displacement efficiency contributed to 28.27%. T2 < 10 ms pore throat contributed the least to the oil displacement efficiency, with an average oil displacement efficiency contribution of 8.58%. Compared with tight sandstone with similar permeability, shale had lower oil displacement efficiency. The findings of this study can help for better understanding of the influence of different injection media on shale oil recovery effect.

scholarly journals Ultra-Low Interfacial Tension Foam System for Enhanced Oil Recovery

2019 ◽  
Vol 9 (10) ◽  
pp. 2155 ◽  
Author(s):  
Qi Liu ◽  
Shuangxing Liu ◽  
Dan Luo ◽  
Bo Peng
Keyword(s):  
Liquid Phase ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Foaming Properties ◽  
Oil Viscosity ◽  
Important Indicator ◽  
Oil Displacement ◽  
Displacement Capacity ◽  
Foam Flooding

The liquid phase of foam systems plays a major role in improving the fluidity of oil, by reducing oil viscosity and stripping oil from rock surfaces during foam-flooding processes. Improving the oil displacement capacity of the foam’s liquid phase could lead to significant improvement in foam-flooding effects. Oil-liquid interfacial tension (IFT) is an important indicator of the oil displacement capacity of a liquid. In this study, several surfactants were used as foaming agents, and polymers were used as foam stabilizers. Foaming was induced using a Waring blender stirring method. Foam with an oil-liquid IFT of less than 10–3 mN/m was prepared after a series of adjustments to the liquid composition. This study verified the possibility of a foam system with both an ultra-low oil-liquid IFT and high foaming properties. Our results provide insight into a means of optimizing foam fluids for enhanced oil recovery.

Flowback Stimulation of Frac Fluid in Tight Oil Reservoirs Through Supercritical Condition

2021 ◽  
Author(s):  
Ying Li ◽  
Ying Ai ◽  
Haitao Li ◽  
Mingjun Chen
Keyword(s):  
Molecular Weight ◽  
Hydraulic Fracturing ◽  
Supercritical Water ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Fracturing Fluid ◽  
Tight Sandstone ◽  
Water Condition ◽  
Water Hydraulic ◽  
Oil Components

Abstract Tight sandstone reservoirs are an important petroleum resources in recent years. Hydraulic fracturing is widely used to stimulate development of tight sandstone oil reservoirs by creating underground fractures, but the low flowback rate of fracturing fluid leads to the water blocking damage and low oil recovery of tight sandstone oil reservoirs compared with those of conventional oil reservoirs. The object of this study is to experimentally investigate the possibility of improving flowback efficiency and oil recovery efficiency through achievement of the supercritical water condition. Self-developed reaction system is used to conduct hydraulic fracturing for tight sandstone samples under both regular and supercritical conditions. While comparing the oil recovery factor and flowback efficiency of the regular and supercritical water hydraulic fracturing, mechanisms behind these results are explored through examination of the change in oil components, the change in rock minerals and the change in pore-fracture distribution. Results show that the dynamic viscosity of the crude oil after the supercritical water hydraulic fracturing is significantly lower than that before hydraulic fracturing, with a decrease of 2.88 mPa·s under ambient condition and a decrease of 0.39 mPa·s under in situ condition. Lighter oil components occupy more percentage of the totoal oil components in the recovered oil from supercritical water hydraulic fracturing than that in the oil recovered from regular hydraulic fracturing, with an average increase of 16% for the oil components of molecular weight from 100 to 200. Heavier oil components of molecular weight larger than 300 have an average decrease of 15.5% after the supercritical water hydraulic fracturing. This indicate the visbreaking of the crude oil under the supercritical water condition. Oil recovery after supercritical water hydraulic fracturing is always higher than that after regular hydraulic fracturing, and the ultimate oil recovery after supercritical water hydraulic fracturing is 66.5% compared with 60% of regular hydraulic fracturing. Fracturing fluid after the supercritical water condition flows much quicker and smoothly than that after the regular hydraulic fracturing, and the ultimate flow back factor of the fracturing fluid is 63% after the supercritical water hydraulic fracturing compared with that of 49% after the regular hydraulic fracturing. Increase in percentage of larger pores/fractures after the supercritical water hydraulic fracturing is more significant than that after regular hydraulic fracturing. The percentage of interstratified illite-montmorillonite decreases an average of 15.2%, while that of kaolinite increase an average of 14.3% in the rock samples after supercritical water hydraulic fracturing compared with the original rock samples. This will benefit the recovery process when oil and water flows together into the well bore after the hydraulic fracturing.

Applied Research of Heat Self-Generated CO2 Technology in Steam Huff and Puff

2014 ◽  
Vol 1010-1012 ◽  
pp. 1693-1698
Author(s):  
Yi Ding ◽  
Guo Wei Qin ◽  
Peng Liu ◽  
Zi Li Fan ◽  
Hong Wei Xiao ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Field Experiments ◽  
Reduction Rate ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Blowing Agent ◽  
Steam Flooding ◽  
Gas Flooding

Heat self-generated CO2 technique is proposed, which is focused on the problems of recovery difficulty, poor effect steam soaking and so on for heavy oil reservoirs. This technology is combining of steam flooding and gas flooding and so on. Its main mechanism is the application of steam heating blowing agent to generate a large volume of gases (including CO2, NH3, etc) in the formation. While some of these gases acting with the oil to reduce the oil viscosity, some form miscible flooding to reduce water interfacial tension, so as to achieve the purpose of enhancing oil recovery. An optimized selection of the heat blowing agents was performed. By comparison the difference before and after the reaction of blowing agent solution, the increase of alkaline is occurred after the reaction, and is helpful to reduce oil viscosity and lower interfacial tension, etc. Studies indicate that heat-generating CO2 flooding technology can get a maximum viscosity reduction rate of 76.7%, oil-water interfacial tension decreased by 54.77%, further improve oil recovery by 4.17% based on the steam drive, which shows a technical advantage toward conventional EOR method. The field experiments indicate that the technique can greatly improve the oil production, which will provide a powerful technical supporting for the efficient development of heavy oil.

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