Enhancement of the imbibition recovery by surfactants in tight oil reservoirs

Meng, Zhan; Yang, Shenglai; Chen, Yan; Zhong, Zhang; Liang, Chenggang; Wang, Lu; Qian, Kun; Ma, Quanzheng; Wang, Junru

doi:10.1007/s12182-018-0253-y

Cited by 38 publications

(21 citation statements)

References 35 publications

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“…Generally, some of tight oil reservoirs are water-wet, so imbibition can happen even if there is no surfactant in the fracturing fluid. However, in some mixed-wet or oil-wet reservoirs, surfactant is usually added into water or the fracturing fluid to promote imbibition by changing the wettability (Begum et al 2017;Alvarez et al 2017;Meng et al 2018;Huang et al 2020). In order to reflect this effect, the capillary force ratio of water to surfactant can be approximated using the Young-Laplace equation assuming constant pore diameter for water and surfactant imbibition,…”

Section: Simulation Of Forced Imbibition With High-pressure Soakingmentioning

confidence: 99%

Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

et al. 2020

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Huff-n-puff by water has been conducted to enhance oil recovery after hydraulic fracturing in tight/shale oil reservoirs. However, the mechanisms and capacity are still unclear, which significantly limits the application of this technique. In order to figure out the mechanisms, the whole process of pressurizing, high-pressure soaking, and depressurizing was firstly discussed, and a mechanistic model was established. Subsequently, the simulation model was verified and employed to investigate the significances of high-pressure soaking, the contributions of different mechanisms, and the sensitivity analysis in different scenarios. The results show that high-pressure soaking plays an essential role in oil production by both imbibition and elasticity after hydraulic fracturing. The contribution of imbibition increases as the increase in bottom hole pressure (BHP), interfacial tension, and specific surface area, but slightly decreases as the oil viscosity increases. In addition, it first decreases and then slightly increases with the increase in matrix permeability. The optimal soaking time is linear with the increases of both oil viscosity and BHP and logarithmically declines with the increase in matrix permeability and specific surface area. Moreover, it shows a rising tendency as the interficial tension (IFT) increases. Overall, a general model was achieved to calculate the optimal soaking time.

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Section: Simulation Of Forced Imbibition With High-pressure Soakingmentioning

confidence: 99%

Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

et al. 2020

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“…The recovery of residual oil by chemical methods accounts for approximately 11% of the worldwide production within the EOR methods [1]. The sweep of hydrocarbons with polymers, which modify the viscosity of water, plays an important role in the oil industry, where China is one of the first countries to use this technique and the only one that has reported oil recovery by chemical methods [2][3][4][5]. Y. Zhu stated that by the end of 2011, in the Daqing oilfield, the oil production was increased by approximately 13% using polymer injection with respect to water sweep [4].…”

Section: Introductionmentioning

confidence: 99%

“…The injection of polymer-flooding agents (PFAs) can improve the oil recovery efficiency, which is of strategic importance in the exploitation of offshore fields, where platform limitations regarding fresh water and space are common features, or for oil fields with high temperatures and/or high salinity congenital water [5,[8][9][10]. On the other hand, well-studied polymers such as polyacrylamides present thermal stability under harsh conditions, and that is why the development of new PFAs is the current topic for many chemical companies and the academic field.…”

Section: Introductionmentioning

confidence: 99%

Macroscopic visual displacement of a polymer solution for enhanced oil recovery: Hele-Shaw cell experiments and computational simulation

et al. 2020

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Numerous laboratory studies and field application tests have shown that polymer flooding is an effective method to improve the oil recovery by displacing residual oil after water flooding. In this work, a series of visual model displacement experiments was conducted in Hele-Shaw cells to determine the effectiveness of polymer flooding in homogeneous and fractured media with a fracture parallel or perpendicular to the flow direction. The matrix with parallel fracture to the flow direction presented a delay in the oil production process during water and polymer flooding with respect to the homogeneous medium and the one with perpendicular fracture, where the highest recovery numbers during waterflooding and polymer flooding were achieved for the medium with perpendicular fracture to the flow direction, reaching 56 % of cumulative oil recovery. The displacement results and multiphasic simulation show that the homogeneous medium is an attractive candidate for additional recovery application with polymer flooding after water ﬂooding when the oil production reached almost zero, although the production rate is lower than the one obtained for a porous medium with a fracture perpendicular to the flow direction.

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“…Wettability alteration of rock surfaces toward water-wet conditions would increase capillary forces, and injection water would imbibe more quickly into the rock (Standnes and Austad 2000a, b;Hirasaki and Zhang 2004;Meng et al 2018;Pal et al 2018).…”

Section: Introductionmentioning

confidence: 99%

Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines

2019

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Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.

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Enhancement of the imbibition recovery by surfactants in tight oil reservoirs

Cited by 38 publications

References 35 publications

Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

Macroscopic visual displacement of a polymer solution for enhanced oil recovery: Hele-Shaw cell experiments and computational simulation

Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines

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