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The prediction of permeability and the evaluation of tight oil reservoirs are very important to extract tight oil resources. Tight oil reservoirs contain enormous micro/nanopores, in which the fluid flow exhibits micro/nanoscale flow and has a slip length. Furthermore, the porous size distribution (PSD), stress sensitivity, irreducible water, and pore wall effect must also be taken into consideration when conducting the prediction and evaluation of tight oil permeability. Currently, few studies on the permeability model of tight oil reservoirs have simultaneously taken the above factors into consideration, resulting in low reliability of the published models. To fill this gap, a fractal permeability model of tight oil reservoirs based on fractal geometry theory, the Hagen–Poiseuille equation (H–P equation), and Darcy's formula is proposed. Many factors, including the slip length, PSD, stress sensitivity, irreducible water, and pore wall effect, were coupled into the proposed model, which was verified through comparison with published experiments and models, and a sensitivity analysis is presented. From the work, it can be concluded that a decrease in the porous fractal dimension indicates an increase in the number of small pores, thus decreasing the permeability. Similarly, a large tortuous fractal dimension represents a complex flow channel, which results in a decrease in permeability. A decrease in irreducible water or an increase in slip length results in an increase in flow space, which increases permeability. The permeability decreases with an increase in effective stress; moreover, when the mechanical properties of rock (elastic modulus and Poisson's ratio) increase, the decreasing rate of permeability with effective stress is reduced. [ABSTRACT FROM AUTHOR]

Reservoir relative permeability is greatly important to the development of water flooding reservoirs. Currently, most researches on relative permeability have not taken the roughness of pore surface and actual fluid distributions into consideration. In this paper, a novel relative permeability model for water flooding reservoirs taking the roughness and actual fluid distributions into consideration has been proposed by using the fractal theory. The novel model contains some key parameters, all of which have clear physical meanings, such as the immobile liquid film thickness, relative roughness, tortuosity fractal dimension D T and pore fractal dimension D f . The predicted results of the novel fractal relative permeability model are consistent with published experimental data. That verifies the correctness of the novel fractal relative permeability model. Finally, sensitive factor analysis of novel relative permeability model is conducted. We can find that the wetting fluid relative permeability decreases as the immobile wetting fluid film thickness or relative roughness increases. When the tortuosity fractal dimension or pore fractal dimension increases, the wetting relative permeability and non-wetting relative permeability will both decrease. An increase in maximum pore diameter or the decreasing of minimum pore diameter results in the reduction in fractal dimension of flow channel and discontinuous saturation. The increasing of maximum pore diameter results in an increase in the relative permeability of wetting fluid. The minimum pore diameter has tiny effect on the relative permeability. [ABSTRACT FROM AUTHOR]

Abstract In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: ①the main fracture linear flow stage, ②the first transition flow stage, ③dual-linear flow stage, ④the second transition flow stage, ⑤the formation linear flow stage, ⑥the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well. Highlights • A transient pressure model with considering threshold pressure gradient and stress sensitivity is proposed. • The model is solved by the Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse. • Model validation is conducted by comparing with existing Ekaterina Stalagorova's model. • Effects of some critical parameters on pressure derivation have been investigated. [ABSTRACT FROM AUTHOR]

Layer recombination is an important technique to improve the oil recovery of waterflooded low-permeability reservoirs, especially at high water cut stage. This technique significantly increases the oil recovery percent of relatively lower-permeability layers when all the formation layers are perforated and produced simultaneously. Parameters such as formation permeability, crude oil viscosity, remaining oil saturation, the presence of hydraulic fractures or others have an impact on the production performance after layer recombination. It is quite difficult to take all these influencing factors into consideration when making layer recombination decisions. Therefore, this paper proposes the ‘apparent mobility’ as the decision index of layer recombination for low-permeability reservoirs at high water cut stage, and the optimal apparent mobility contrast values for layer recombination under different producing pressure drop are obtained. The equivalent permeability of fractured layers is introduced into the apparent mobility. This technique has been applied to the layer recombination treatment of Block Five of Bonan oilfield in Shengli oilfield of SINOPEC, and the oil recovery increased approximately 3.1% compared with the previous commingling production scenario, which confirmed the validity of this proposed method. [ABSTRACT FROM AUTHOR]

A new relationship between the ratio of water and oil relative permeability, and the water saturation is proposed based on the flow characteristic in porous media in the ultra-high water cut stage which results in a new water flooding characteristic curve with reservoir engineering method. Then a new algorithm to forecast development indexes is derived on the basis of the new relationship above, the new water flooding characteristic curve and the production decline law using Welge equation in which there are many parameters including time, water cut, the average water saturation and the oil recovery that can be used to evaluate the recoverable reserve. Through the examinations with the numerical simulation method and the on-site application, it shows that the new algorithm can give an accurate prediction with an relative error less than 6 %, which is instructive for the oil field development. [ABSTRACT FROM AUTHOR]