Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives

Liang, Tianbo; Longoria, Rafael A.; Lu, Jun; Nguyen, Quoc P.; DiCarlo, David A.

doi:10.2118/175101-pa

Cited by 82 publications

(33 citation statements)

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“…The corresponding matrix notation is f = kd (19) where and are the node force, N; k is the stiffness matrix of the spring element, N/m; d is the node displacement vector, m; f is the node force vector, N. During SLFTP, the previously created fractures were plugged by diverting agents; thus the injected fracturing fluid and proppants were not able to flow back to the wellbore and retained within fractures. Moreover, the fluid leak-off rate was low due to the low-permeability [36][37][38]; thus the fracturing fluid and proppants trapped in the fracture space will prevent the previous fractures from closure. The propped fractures would squeeze the surrounding rocks and alter local stress fields, which may affect the injection pressure of the subsequent fractures created in other layers.…”

Section: Spring Modelmentioning

confidence: 99%

Evaluations of Fracture Injection Pressure and Fracture Mouth Width during Separate-Layer Fracturing with Temporary Plugging

Wang

Zhou

Liang

et al. 2018

Mathematical Problems in Engineering

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Separate-layer fracturing with temporary plugging (SLFTP) is a potential way to stimulate multiple layer reservoirs due to its low cost, low risk, and high efficiency. In this study, based on the cohesive zone model (CZM), a 3D fully fluid-solid coupling and multiple layer model is established to investigate factors influencing fracture injection pressure and fracture mouth width. The cohesive layer properties are based on the reported study, which have been validated through a series of numerical experiments. Innovatively, the spring model is innovatively proposed to represent the plugging effect of diverting agents and prop the aperture of the previous fractures. Simulation results reveal that the effects of previous fractures in multiple layer formations can be neglected, which is quite different from multistage fracturing for horizontal wells. Fracture injection pressure can be evaluated more accurately by taking the following factors into consideration: the minimum horizontal principal stress, rock tensile strength, injection rate, and pore pressure enhancement. Further, fracture mouth width is strongly influenced by rock tensile strength, Young’s modulus, and injection rate. This study provides a guidance for candidate well selection and diverting agent optimization during SLFTP in multilayer formations.

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Section: Spring Modelmentioning

confidence: 99%

Evaluations of Fracture Injection Pressure and Fracture Mouth Width during Separate-Layer Fracturing with Temporary Plugging

Wang

Zhou

Liang

et al. 2018

Mathematical Problems in Engineering

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“…Although the above method can effectively improve the oil recovery of low‐permeability oil layers, there are still many deficiencies. For hydraulic fracturing technology, only a small part of the injected fracturing fluid can be recovered, and most of the injected fracturing fluid remains in the formation, 29,30 and the remaining fracturing fluid plugs the original connected pores and throats, resulting in a decrease in physical permeability 31 . In addition, the residual fracturing fluid may form two‐phase seepage resistance and reduce the effective permeability of the oil phase 32 ; for CO 2 flooding, CO 2 injection may bypass the remaining oil zone and tend to flow through fractures, resulting in low sweep efficiency 33‐35 ; for profile control, the injected gel permanently blocks the high‐permeability layer 36 .…”

Section: Introductionmentioning

confidence: 99%

Experimental evaluation of ASP flooding to improve oil recovery in heterogeneous reservoirs by layered injection approach

Huang

et al. 2020

Energy Science & Engineering

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To improve the oil displacement effect of ASP (alkali/surfactant/polymer) solution in heterogeneous oil reservoirs, layered injection technology is proposed for the first time for Daqing Oilfield. The technology uses partial pressure tools to control the injection amount of ASP solution in high‐permeability oil layers and uses a partial quality tool in low‐permeability oil layers. To study the experimental effect of this layered injection technology, the relationships between the different permeability, molecular weight, and concentration of the ASP solution, as well as the resistance coefficient and residual resistance coefficient, are first established, and then, a layered injection experimental model is established to carry out experimental research on injection capacity and oil displacement capacity. The experimental results show that the smaller the range of the core permeability is, the larger the molecular weight and concentration of the ASP solution are, and the poorer the injection capacity of the ASP solution is. After the action of a partial pressure tool and a partial quality tool, the injection capacity of ASP solution is improved to different degrees, and the oil displacement effect of low‐permeability cores is significantly improved, while the total oil recovery is increased, and the total oil recovery of heterogeneous cores under different conditions is increased by 1.4%‐4.05%. This experiment is of great significance to the study of improving the oil recovery of heterogeneous reservoirs.

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“…In water-wet rocks, it is observed that the water block formed by the invaded fracture fluid predominantly exists at the matrix-fracture interface due to the capillary discontinuity between the high-permeable fracture and low-permeable matrix space surrounding it [4] [5]. Bertoncello et al (2014) [6], Liang et al (2015) [7], Odumabo et al (2014) [8] and Yan et al (2015) [9] have shown that with sufficient duration of shut-in period the water-block would imbibe away from the fracture face due to capillary redistribution resulting in improvement of relative permeability to hydrocarbon. But very long shut-in times could affect the operator adversely as the expenditures increase due to the high day-rate services offered by the service companies.…”

Section: Introductionmentioning

confidence: 99%

Chip Flood (vs) Core Flood—Assessment of Flowback and Oil Productivity in Oil-Wet Hydraulic Fractured Rocks

Tangirala¹,

Sheng²,

Tu³

2019

OJOGas

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New developments in lab technologies help us to explore problems that were less understood in the past due to the limitations and technological constraints. One such problem of assessing the formation damage created by the invasion of fracture fluid into the matrix at lab scale is the visualization of fluid saturation distributions inside the matrix. According to the current understanding, the high capillarity contrast between the fracture and the matrix creates a non-uniform saturation distribution of invaded fluid phase during flowback, with the saturations mostly concentrated at the fracture face. With the advent of microfluidics, their application has become more feasible to visually analyze the effectiveness of surfactants to mitigate the invasion-created formation damage and understand the impact of depth of invasion on the characteristics of flowback and oil productivity. Through our previous work, we have successfully demonstrated the capability of this new visualization tool in studying the factors of the presence of surfactant in the fracture fluid and its depth of invasion, to understand the flowback efficiencies and later oil productivities in oil-wet fractured formations. Since the substrate for flooding was a proxy model of an actual rock, the chip flooding results need to be validated with conventional core flooding experiments. In contemporary times, when the new advancements in technology are driving the research progress in all industries, it is mandatory to take a well informed decision by imposing a comparative check on the results with accessible conventional means, wherever possible. The success of validation of chip flooding approach with the core flooding approach in this work instates a strong belief over the application of microfluidics to pursue more research in related fields of oil recovery.

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Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives

Cited by 82 publications

References 1 publication

Evaluations of Fracture Injection Pressure and Fracture Mouth Width during Separate-Layer Fracturing with Temporary Plugging

Evaluations of Fracture Injection Pressure and Fracture Mouth Width during Separate-Layer Fracturing with Temporary Plugging

Experimental evaluation of ASP flooding to improve oil recovery in heterogeneous reservoirs by layered injection approach

Chip Flood (vs) Core Flood—Assessment of Flowback and Oil Productivity in Oil-Wet Hydraulic Fractured Rocks

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