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.

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 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 Effect of Pore-Throat Microstructures on Formation Damage during Miscible CO2 Flooding of Tight Sandstone Reservoirs

2020 ◽  
Vol 34 (4) ◽  
pp. 4338-4352 ◽  
Author(s):  
Qian Wang ◽  
Shenglai Yang ◽  
Paul W. J. Glover ◽  
Piroska Lorinczi ◽  
Kun Qian ◽  
...  
Keyword(s):  
Formation Damage ◽  
Co2 Flooding ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Sandstone Reservoirs

Experimental study of oil recovery from pore of different sizes in tight sandstone reservoirs during CO2 flooding

2021 ◽  
pp. 109740
Author(s):  
Xiang Li ◽  
Junjie Xue ◽  
Yanqing Wang ◽  
Weipeng Yang ◽  
Jun Lu
Keyword(s):  
Experimental Study ◽  
Oil Recovery ◽  
Co2 Flooding ◽  
Tight Sandstone ◽  
Sandstone Reservoirs

scholarly journals Influence of CO2-brine-rock Interactions on the Physical Properties of Tight Sandstone Cores via Nuclear Magnetic Resonance

2021 ◽  
Vol 898 (1) ◽  
pp. 012021
Author(s):  
Hanbin Liu ◽  
Chengzheng Li ◽  
Zhenfeng Zhao ◽  
Guangtao Wang ◽  
Changheng Li ◽  
...  
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Physical Properties ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Low Permeability ◽  
Pore Throat ◽  
Tight Sandstone ◽  
The Core ◽  
Before And After ◽  
Enhance Oil Recovery

Abstract For sandstone reservoirs with extra-low permeability, CO2 injection is regarded as a valid method to enhance oil recovery. When CO2 injection is implemented in such reservoirs, the physical properties of the formation could be altered owing to the interactions between CO2, water, and rock. In this study, the influence of CO2–brine–rock interactions on the physical properties of tight sandstone cores was analyzed by comparing the obtained T 2 spectrum before and after CO2 injection. The results revealed that the T2 spectrum after CO2 injection was significantly different from the original T2 spectrum. CO2 injection changed the pore size distribution of the core samples. When the injection pressure was low, the pore volume decreased from micropores to macropores leading to a decrease in both permeability and porosity. As the injection pressure increasing, the dissolution of CO2 in the micropores was enhanced thus improving the pore-throat connectivity; which ultimately improved the reservoir physical properties.

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 Comparison of Nanomaterials for Enhanced Oil Recovery in Tight Sandstone Reservoir

2021 ◽  
Vol 9 ◽  
Author(s):  
Chenjun Zhang ◽  
Xu Jin ◽  
Jiaping Tao ◽  
Bo Xiong ◽  
Zhijian Pan ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Ordos Basin ◽  
Average Particle Size ◽  
Petroleum Engineering ◽  
Scanning System ◽  
Average Particle ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Displacement Effect ◽  
Sandstone Reservoir

With dwindling conventional oil resources, the development of high-performance oil-displacing agents to exploit unconventional oil and gas resources has become a research focus, and new technical ideas have been proposed for petroleum engineering with the advancement of nanomaterials and technology. This study characterized the microscopic pore throat structure of the unconventional tight sandstone reservoir of Ordos Basin in China comprehensively by using high-resolution scanning electron microscopy, image panoramic mosaic technology, mineral quantitative scanning system, and 3D image of pore. A new nanofluid with diphenyl ether surfactants as shell and C10–C14 straight-chain hydrocarbon compounds as kernel was prepared according to the features of tight sandstone reservoirs. The basic physical properties of the nanofluid were evaluated and compared with those of three other generic oil-displacing agents to understand the oil-displacement effect and mechanism. Results show that this nanofluid remains relatively stable and dispersible with aging and its average particle size matches well with the pore throat size of the target reservoir, which increases the sweep volume effectively. Additionally, the change from oil-wet to water-wet can exert capillary imbibition. And the oil-water interfacial tension can be greatly reduced to the level of 10–2 mN/m because of nanofluid’s excellent interfacial activity, which improves the efficiency of oil washing in nano-scale pore throats. Finally, the core imbibition experiment further demonstrated the superiority of the nanofluid. Using the nanofluid in optimal concentration with cores of approximately 0.1 mD can achieve a recovery rate of 37.5%, which is higher than generic oil-displacing agents by up to 9%. This study demonstrates that the excellent performance of nanofluid in enhancing oil recovery and provides a reference for the development of unconventional reservoirs, which are difficult to function with generic agents.

Preculaatities of evaluation of the effectiveness of flow deflection technologies

2018 ◽  
pp. 93-101
Author(s):  
A. A. Kazakov ◽  
V. V. Chelepov ◽  
R. G. Ramazanov
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Production Well ◽  
Oil Companies ◽  
Efficiency Calculation ◽  
Petroleum Companies ◽  
Flow Deflection ◽  
Recovery Methods

The features of evaluation of the effectiveness of flow deflection technologies of enhanced oil recovery methods. It is shown that the effect of zeroing component intensification of fluid withdrawal leads to an overestimation of the effect of flow deflection technology (PRP). Used in oil companies practice PRP efficiency calculation, which consists in calculating the effect on each production well responsive to subsequent summation effects, leads to the selective taking into account only the positive components of PRP effect. Negative constituents — not taken into account and it brings overestimate over to overstating of efficiency. On actual examples the groundless overstating and understating of efficiency is shown overestimate at calculations on applied in petroleum companies by a calculation.

scholarly journals A reservoir quality evaluation approach for tight sandstone reservoirs based on the gray correlation algorithm: A case study of the Chang 6 layer in the W area of the as oilfield, Ordos Basin

2021 ◽  
pp. 014459872199851
Author(s):  
Yuyang Liu ◽  
Xiaowei Zhang ◽  
Junfeng Shi ◽  
Wei Guo ◽  
Lixia Kang ◽  
...  
Keyword(s):  
Quality Evaluation ◽  
Comprehensive Evaluation ◽  
Ordos Basin ◽  
Reservoir Quality ◽  
Pore Throat ◽  
Tight Sandstone ◽  
Evaluation Approach ◽  
Correlation Algorithm ◽  
Gray Correlation ◽  
Sandstone Reservoir

As an important type of unconventional hydrocarbon, tight sandstone oil has great present and future resource potential. Reservoir quality evaluation is the basis of tight sandstone oil development. A comprehensive evaluation approach based on the gray correlation algorithm is established to effectively assess tight sandstone reservoir quality. Seven tight sandstone samples from the Chang 6 reservoir in the W area of the AS oilfield in the Ordos Basin are employed. First, the petrological and physical characteristics of the study area reservoir are briefly discussed through thin section observations, electron microscopy analysis, core physical property tests, and whole-rock and clay mineral content experiments. Second, the pore type, throat type and pore and throat combination characteristics are described from casting thin sections and scanning electron microscopy. Third, high-pressure mercury injection and nitrogen adsorption experiments are optimized to evaluate the characteristic parameters of pore throat distribution, micro- and nanopore throat frequency, permeability contribution and volume continuous distribution characteristics to quantitatively characterize the reservoir micro- and nanopores and throats. Then, the effective pore throat frequency specific gravity parameter of movable oil and the irreducible oil pore throat volume specific gravity parameter are introduced and combined with the reservoir physical properties, multipoint Brunauer-Emmett-Teller (BET) specific surface area, displacement pressure, maximum mercury saturation and mercury withdrawal efficiency parameters as the basic parameters for evaluation of tight sandstone reservoir quality. Finally, the weight coefficient of each parameter is calculated by the gray correlation method, and a reservoir comprehensive evaluation indicator (RCEI) is designed. The results show that the study area is dominated by types II and III tight sandstone reservoirs. In addition, the research method in this paper can be further extended to the evaluation of shale gas and other unconventional reservoirs after appropriate modification.

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