Comparative study of well soaking timing (pre vs. post flowback) for water blockage removal from matrix-fracture interface

Wijaya, Nur; Sheng, James J.

doi:10.1016/j.petlm.2019.11.001

Cited by 25 publications

(5 citation statements)

References 7 publications

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“…During the shut-in time, matrix water saturation at the bottom of the reservoir increases due to the imbibition of the remaining slickwater in the fractures (Wijaya and Sheng 2019 , 2020 ). As shown in Fig.…”

Section: Resultsmentioning

confidence: 99%

Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation

Bui

Nguyen

Nguyễn

et al. 2022

J Petrol Explor Prod Technol

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Formation damage in drilling comes from drilling fluid invasion due to high differential pressure between a wellbore and the formation. This mechanism happens with fracture fluid invasion of multi-fractured horizontal wells in tight formations. Some multi-fractured wells show production rates and cumulative productions far lower than expected. Those damaged wells may sustain further impact such as well shutting due to unexpected events such as the COVID-19 outbreak and then experience a further reduction in cumulative production. This paper focuses on the root causes of formation damage of fractured wells and provides possible solutions to improve production. A simulation study was conducted using Computer Modelling Group software to simulate formation damage due to fracture fluid invasion and well shut-in. Simulation results revealed that the decrease in cumulative hydrocarbon production due to leak-off and shut-in of the simulated well could range from 20 to 41%, depending on different conditions. The results showed that the main causes are high critical water saturation of tight formations, low drawdown, and low residual proppant permeability under formation closure stress. The sensitivity analysis suggests two feasible solutions to mitigate formation damage: optimizing drawdown during production and optimized proppant pack permeability of the hydraulic fracturing process. Optimizing pressure drawdown is effective in fixing leak-off damage, but it does not mitigate shut-in damage. Formation damage due to shut-in should be prevented in advance by using an appropriate proppant permeability. These key findings enhance productivity and improve the economics of tight gas and shale oil formations.

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Section: Resultsmentioning

confidence: 99%

Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation

Bui

Nguyen

Nguyễn

et al. 2022

J Petrol Explor Prod Technol

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“…There are obvious differences in the oil breakthrough time, flowback rate, water cut, and daily oil production of different shale oil wells. Proper well shut-in or the addition of a chemical agent to promote imbibition is conducive to improving the initial productivity. , Wijaya et al , used imbibition data for the Middle Bakken shale oil reservoir to perform reservoir numerical simulations with accounting for the compaction-dominant and imbibition-dominant mechanisms. They showed that only when shale reservoirs have a strong imbibition capacity is the situation favorable to oil recovery.…”

Section: Imbibition At the Reservoir Scalementioning

confidence: 99%

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

et al. 2023

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The breakthrough of shale oil in North America led to a worldwide energy revolution. Shale reservoirs show multiscale properties and a large proportion of nanopores compared to conventional reservoirs, which makes the imbibition mechanisms of fracturing fluids within shale reservoirs exceptionally complicated. For instance, the fracturing fluid shows a distinct imbibition behavior at different scales. Traditional models face significant challenges in imbibition characterization. Understanding the imbibition mechanisms in shale oil formations from a multiscale perspective can help to make full use of the positive effect and enhance oil recovery. We review imbibition mechanisms in shale reservoirs from the nanoscale to the reservoir scale. The imbibition principles in a single nanopore and the improvement of the traditional characterization models are clarified. Then, at the pore scale, we elaborate on the imbibition laws obtained from the microfluidic chip, pore network model, and direct simulations. We also outline the imbibition dynamics at the core scale, the influences of capillary forces and osmotic pressure, and the variations of the pore structure. Finally, the imbibition behavior at the reservoir scale and field examples considering the imbibition effect are introduced. We analyze the existing problems on each scale and discuss the future trends in this area. This work is expected to help readers systematically understand the mechanisms and behavior of fracturing fluid imbibition in shale oil reservoirs at different scales and accelerate the exploitation of shale resources.

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“…The current stage of operation of the Dragon field is exacerbated by the problems associated with the fact that the field is in the falling stage of development characterized by a further increase in negative factors: uneven production of reserves, increase of water content, increase of hard-to-recover reserves, increase of oil viscosity associated with its oxidation upon contact with oxygen dissolved in water injected into a reservoir, increase of concentration of asphalt-resin substances, aging and wear of well stock, etc. [11,12].…”

Section: Introductionmentioning

confidence: 99%

Laboratory studies on the use of surfactant compositions to solve resource extraction problems

Ngia¹,

Veliev²,

Mukhametshin

et al. 2022

IOP Conf. Ser.: Earth Environ. Sci.

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Based on studies on the interaction and heat resistance of some heat-resistant polymer additives at 128 °C, a sulfonated polyacrylamide polymer AN-125 is proposed as an additive for improving the viscosity of a surfactant composition. The results of experimental studies of a new surfactant composite prepared based on a mixture of ethoxylated and propoxylated sulfate, α-olefin sulfonate and alkylphenol ethoxylate with a concentration of 500 ppm and additives to improve the viscosity in the reservoir model from the deposit basement samples showed that the surface tension at the oil-solution boundary before the exposure to temperature is 0.19 mN/m, and after exposure to temperature 91 °C – 0.21 mN/m. The experimental studies of water and surfactant compositions injection on 5 prefabricated models composed of core samples of basement rocks covering a wide range of reservoir properties showed that the injection of the oil rim with compositions based on the mixture of ethoxylated and propoxylated sulfate, α-olefin sulfonate and alkylphenol ethoxylate with a concentration of 800 ppm and an additive of polymerasulfonated polyacylate increases the oil displacement ratio.

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Comparative study of well soaking timing (pre vs. post flowback) for water blockage removal from matrix-fracture interface

Cited by 25 publications

References 7 publications

Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation

Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

Laboratory studies on the use of surfactant compositions to solve resource extraction problems

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