Effect of Salinity on the Imbibition Recovery Process of Tight Sandstone Reservoirs

Liu, Xiong; Yan, Le; Gao, Qian; Liu, Yafei; Huang, Hai; Liu, Shun

doi:10.3390/pr10020228

Cited by 4 publications

(3 citation statements)

References 24 publications

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“…Surfactants primarily increase recovery by reducing surface tension and altering wettability, whereas imbibition agents enhance the fracturing fluid's penetration ability to achieve improved recovery. Integrated fracturing and recovery fluids utilize mechanisms such as interfacial adsorption, wettability alteration, micellar solubilization, and oil-water displacement to induce spontaneous imbibition and enhance crude oil recovery efficiency [19][20][21][22][23][24].…”

Section: Characteristics Of Integrated Fracturing and Enhanced Recove...mentioning

confidence: 99%

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Shang,

Dong,

Tan

et al. 2024

Processes

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Tight reservoirs, characterized by low porosity, low permeability, and difficulty in fluid flow, rely on horizontal wells and large-scale hydraulic fracturing for development. During fracturing, a significant volume of fracturing fluid is injected into the reservoir at a rate far exceeding its absorption capacity. This not only serves to create fractures but also impacts the recovery efficiency of tight reservoirs. Therefore, achieving the integration of fracturing and enhanced recovery functions within the working fluid (fracturing-enhanced recovery integration) becomes particularly crucial. This study describes the concept and characteristics of fracturing-enhanced recovery integration and analyzes the types and features of working fluids. We also discuss the challenges and prospects faced by these fluids. Working fluids for fracturing-enhanced recovery integration need to consider the synergistic effects of fracturing and recovery; meet the performance requirements during fracturing stages such as fracture creation, proppant suspension, and flowback; and also address the demand for increased recovery. The main mechanisms include (1) enlarging the effective pore radius, (2) super-hydrophobic effects, and (3) anti-swelling properties. Fracturing fluids are pumped into fractures through pipelines, where they undergo complex flow in multi-scale fractures, ultimately seeping through capillary bundles. Flow resistance is influenced by the external environment, and the sources of flow resistance in fractures of different scales vary. Surfactants with polymerization capabilities, biodegradable and environmentally friendly bio-based surfactants, crosslinking agents, and amino acid-based green surfactants with outstanding properties will unleash their application potential, providing crucial support for the effectiveness of fracturing-enhanced recovery integration working fluids. This article provides important references for the green, efficient, and sustainable development of tight oil reservoirs.

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Section: Characteristics Of Integrated Fracturing and Enhanced Recove...mentioning

confidence: 99%

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Shang,

Dong,

Tan

et al. 2024

Processes

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“…These tight reservoirs are predominantly developed via the huff-n-puff method, with enhanced oil production facilitated by spontaneous imbibition. , Consequently, the challenge of brine flooding in tight reservoirs is not a significant concern. The investigation by Liu et al observed that salinity exerts a significant influence on interfacial tension. In the presence of surfactants, the impact of brine salinity on interfacial tension may be negligible, while the salinity effect plays a crucial role in the imbibition process of tight oil reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Experimental Investigation on the Interfacial Characteristics of Tight Oil Rocks Induced by Tuning Brine Chemistry

Cheng,

Tong,

Wang

et al. 2024

ACS Omega

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Currently, research on enhancing imbibition oil recovery in tight oil reservoirs through the ion-tuning technique remains limited. Two critical parameters for capillary imbibition are the wettability and interfacial tension between oil and water. In this investigation, we manipulate the properties of two types of formation water for both aged and unaged samples by diluting brine and altering ion composition. Subsequently, we employ captive and pendant-drop methods to assess rock wettability and interfacial tension under varied brine conditions. Additionally, we elucidate the primary mechanisms underlying changes in rock wettability and interfacial tension. Meanwhile, we analyze capillarity characteristics and assess the relative significance of wettability and interfacial tension. Results indicate that there is a critical interfacial tension with progressive dilution of two types of formation water. However, modifying ion composition leads to a complex trend in interfacial tension, which can be explained qualitatively through the Gibbs adsorption isotherm. For unaged samples, the contact angle demonstrates a pronounced water-wet characteristic, showing a nonmonotonic trend with respect to dilution times. Remarkably, the rock surface exhibits the strongest water-wet, particularly evident in the case of FW-10, largely influenced by variations in interfacial tension. Conversely, aged samples demonstrate strong oil-wet, with a critical salinity resulting in the lowest contact angle, while altering brine ion types can alter rock wettability from strongly oil-wet to intermediate-wet, which is not sufficient to result in the wettability alteration. The removal of multivalent cations is proposed as the most effective method for wettability modification. Furthermore, capillarity variations among different brine cases are primarily contingent upon contact angle changes, and interfacial tension does not have a significant change when regulating the brine properties. Consequently, we emphasize the significance of wettability in the adoption of ion-tuned brine techniques for tight oil reservoirs. Overall, our study underscores the potential of reasonably regulating brine properties to enhance capillarity and, thereby, improve imbibition oil recovery.

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“…From the early stage of oilfield development to the middle and late stages with high water production, the recovery rate of tight sandstone reservoirs has decreased day by day. It has become a key task to make a strategy to enhance oil recovery by studying the controlling effect of pore permeability on residual oil (Li C. et al, 2022; [3,4].…”

Section: Introductionmentioning

confidence: 99%

Microscopic Distribution and Development Strategy of Residual Oil in Tight Sandstone

Zhang

Mu³

2023

Processes

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Pore and permeability are distributed discontinuously and unevenly in the dominant sedimentary model of the lateral accretion body inside the meandering river point bar of the Fuyang reservoir of the Yushulin oilfield. Based on the water flooding experiments of field core samples, the influence of pore permeability conditions on residual oil distribution type and water cutting rate was studied by using the microscopic visualization technology enabled through a photolithographically fabricated glass model. It is found that the residual oil in samples shows five discontinuous types, which are cluster, columnar, oil droplet, membrane, and blind end. In the stages with low, medium, and high water cutting rates, the proportion of clustered residual oil in the samples with different permeability is high, reflecting the situation that it is difficult for injected water to spread widely in tight oil reservoirs. With the decrease of permeability, the proportion of membrane and blind end residual oil gradually increases, which indicates that the thin pore throat can produce large restrictions on residual oil, resulting in residual oil enrichment. At the same time, the water flooding experiment was carried out by changing the displacement direction and periodic water injection. It was found that changing the displacement direction was beneficial to the recovery of residual oil in the thin pore throat and avoided the dominant seepage of injected water in the big pore throat, and the recovery rate was increased by more than 2.14%. Periodic water injection, which was conducive to adjusting the displacement pressure difference, reduced the constraining force of the throat on residual oil and increased the recovery rate by more than 3.98%. The actual well area with closed coring wells and dynamic production data is preferred for the application of experimental research results. Changing displacement direction and periodic water injection increased the residual oil recovery by more than 3%.

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Effect of Salinity on the Imbibition Recovery Process of Tight Sandstone Reservoirs

Cited by 4 publications

References 24 publications

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Experimental Investigation on the Interfacial Characteristics of Tight Oil Rocks Induced by Tuning Brine Chemistry

Microscopic Distribution and Development Strategy of Residual Oil in Tight Sandstone

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