Parameter Prediction of Water Imbibition in Unsaturated Shales Using the NMR Method

Yang, Jun Han; Leng, Jingyi; Qiao, Linke; Wang, Linlin; Ding, Jiadi

doi:10.1155/2019/4254159

Cited by 13 publications

(9 citation statements)

References 42 publications

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“…When the fracturing fluid enters the reservoir, the oil and gas in shale pores can be replaced and recovered. Spontaneous imbibition is thought as an important means for the exploitation of shale gas, and the study of spontaneous imbibition in fractured shale is of great significance. − According to the different movement directions of wetting and nonwetting phases, it can be divided into countercurrent and cocurrent imbibition . When the matrix blocks are completely immersed in the wetting phase, the two phases could displace in the opposite direction.…”

Section: Introductionmentioning

confidence: 99%

Effects of Fracture Characteristics on Spontaneous Imbibition in a Tight Reservoir

et al. 2021

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Horizontal well fracturing technology is widely used in the development of shale gas resources. After the fracturing operations, natural and artificial fractures exist in the reservoir at the same time, which has significant effects on spontaneous imbibition to increase shale gas production. Based on nuclear magnetic resonance technology, this work studies the spontaneous imbibition property of fractured shale, including artificial and natural fractures, surface cemented minerals, boundary conditions, etc. The results show that the relaxation time spectra reflect the characteristics of water and gas migration in the rock pore space. The micropores and the small pores are the main storage space for water in shale. After water imbibition starts, the imbibition volume is roughly proportional to the square root of time. Through the comparative experiments on artificial fractures, natural fractures, and seamless cores, it is found that the existence of fractures can significantly promote water imbibition, and the imbibition speed of artificial fractured cores is faster than those of others. Because of the existence of artificial and natural fractures, the number of pores for gas discharge increases, and the imbibed volume is slightly more. When the cemented minerals such as quartzite and calcite are attached to the core surface, they have poor water sensitivity and block some of the pores, thus resulting in a slower imbibition speed. Different boundary conditions will not only affect the contact area between the core and water but also influence the types of imbibition, which changes the water flow path and imbibition speed. This study provides an important insight into spontaneous imbibition in gas shale after the fracturing operations.

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Section: Introductionmentioning

confidence: 99%

Effects of Fracture Characteristics on Spontaneous Imbibition in a Tight Reservoir

et al. 2021

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“…Other studies on boundary conditions give more consideration to capillary imbibition than diffusion imbibition 10,15 and only a few studies have mentioned the influence of other forces such as diffusion, osmosis, or surface hydration. 8,16 A low flowback rate suggests that the overall imbibition process may also be greatly influenced by diffusion imbibition, which is slower because capillary imbibition mainly occurs at the early stage of the imbibition process while diffusion takes over as capillary forces decrease at the later stage of the imbibition process. The contribution of both capillary and diffusion imbibition mechanisms has not been simultaneously explored under different boundary conditions.…”

Section: Introductionmentioning

confidence: 99%

NMR Investigation of Brine Imbibition Dynamics in Pores of Tight Sandstones under Different Boundary Conditions

Umeobi

et al. 2021

Energy Fuels

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This study explores imbibition dynamics and flowback of fracturing fluids in Penglaizhen sandstones by imbibition experiment and nuclear magnetic resonance analysis. A gas–water system was considered and samples were subjected to different boundary conditions and fully immersed in the wetting phase for imbibition. A close range of the pore radius was observed between 0.1 nm and 9.3 μm for all samples. Basic features of the imbibition phases were represented by the imbibition profile, and imbibition parameters were quantified in terms of gas recovery, imbibition capacity, imbibition index and pore connectivity, diffusion ability, and imbibition potential under the respective boundary conditions. The study reveals that capillary imbibition (mainly in all-face-open (AFO) and two-end-closed (TEC)) and diffusion imbibition (mainly in two-end-open (TEO) and one-end-open (OEO)) are the major mechanisms by which fracture fluids flow into the formation matrix. There is high gas recovery in all samples (>79%), which can be attributed to the high water-wet nature of the samples, while the residual gas saturation is very low with the highest value in OEO at 0.17 and the lowest in AFO at 0.01. The strong capillary force in AFO and TEC boundary conditions is the key factor for higher gas recovery than TEO and OEO samples. However, the low diffusion ability of AFO and TEC samples depict a low gas displacement effect. On the other hand, TEO and OEO boundary conditions show an increased gas displacement effect through increased diffusion ability. The imbibition index (which represents pore connection) and imbibition potential from the highest to the lowest also correspond to the diffusion ability from the highest to the lowest.

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“…Based on the capillary pressure curve in the rock core, the area difference of the capillary pressure curve and the correlation coefficient were calculated. en, the boundary value was transformed according to the step size, and the leastsquare automatic iteration was used to search for the minimum area difference and the maximum correlation coefficient between the core capillary pressure curve and the pseudo-capillary pressure curve [31][32][33]. By calculating the pseudo-capillary pressure curve of each rock sample and comparing it with the core capillary pressure curve, the absolute error between the two curves was calculated.…”

Section: Inversion Methods Of Apparent Free Water Porosity Based On Nmr Loggingmentioning

confidence: 99%

Fluid Identification Based on NMR Apparent Free Water Porosity Inversion: A Case Study of Paleozoic Tight Sandstone Gas Reservoirs in Western Ordos

et al. 2022

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Tight sandstone reservoirs are affected by various factors such as pore structure, formation water salinity, and siliceous cementation, which lead to the abnormal phenomenon of high-resistivity water layers and increase the difficulty in identifying gas and water layers by conventional logging. In this study, the pore types and pore size distribution characteristics of tight sandstone reservoirs were firstly determined by NMR and high-pressure mercury injection experiments, and then the iterative least-square method was used to automatically optimize the inversion method of pseudo-capillary pressure curve and search for the optimal conversion coefficient. Finally, the apparent free water porosity was inversed and the fluid identification standard was obtained and applied. The results showed that the reservoirs mainly developed intergranular pores, cutting solution pores, and intergranular pores. The pore throats were poorly sorted, and the displacement pressure was high. The median radius ranged from 0.01 to 0.48 μm, and the main peak range was from 0.02 to 0.06 μm. Pores were of mainly small-hole fine throat type. In the inversion results of the optimal conversion coefficient, the correlation coefficient between the aperture parameters and the results of high-pressure mercury injection experiments was greater than 0.93. According to the fluid property identification standard based on nuclear magnetic apparent free water porosity, the high-resistivity water layers were effectively identified and its coincidence rate with the final field test was 10.7% higher than that of the conventional method. This identification method can be used to identify complex fluids in tight sandstone reservoirs.

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Parameter Prediction of Water Imbibition in Unsaturated Shales Using the NMR Method

Cited by 13 publications

References 42 publications

Effects of Fracture Characteristics on Spontaneous Imbibition in a Tight Reservoir

Effects of Fracture Characteristics on Spontaneous Imbibition in a Tight Reservoir

NMR Investigation of Brine Imbibition Dynamics in Pores of Tight Sandstones under Different Boundary Conditions

Fluid Identification Based on NMR Apparent Free Water Porosity Inversion: A Case Study of Paleozoic Tight Sandstone Gas Reservoirs in Western Ordos

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