scholarly journals Dynamic capillary pressure analysis of tight sandstone based on digital rock model

Capillarity ◽  
2020 ◽  
Vol 3 (2) ◽  
pp. 28-35 ◽  
Author(s):  
Yixin Cao ◽  
Mingming Tang ◽  
Qian Zhang ◽  
Jiafan Tang ◽  
Shuangfang Lu
Keyword(s):  
Capillary Pressure ◽  
Tight Sandstone ◽  
Digital Rock ◽  
Dynamic Capillary Pressure ◽  
Rock Model ◽  
Pressure Analysis

Performance Evaluation of Gas Production With Consideration of Dynamic Capillary Pressure in Tight Sandstone Reservoirs

2018 ◽  
Vol 141 (2) ◽  
Author(s):  
Leng Tian ◽  
Bo Feng ◽  
Sixu Zheng ◽  
Daihong Gu ◽  
Xiaoxing Ren ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Production Rate ◽  
Water Saturation ◽  
Gas Production ◽  
Tight Sandstone ◽  
Mobile Water ◽  
Dynamic Capillary Pressure ◽  
Irreducible Water Saturation ◽  
Sandstone Reservoirs ◽  
Bottomhole Pressure

In this paper, a pragmatic and consistent framework has been developed and validated to accurately predict reservoir performance in tight sandstone reservoirs by coupling the dynamic capillary pressure with gas production models. Theoretically, the concept of pseudo-mobile water saturation, which is defined as the water saturation between irreducible water saturation and cutoff water saturation, is proposed to couple dynamic capillary pressure and stress-induced permeability to form an equation matrix that is solved by using the implicit pressure and explicit saturations (IMPES) method. Compared with the conventional methods, the newly developed model predicts a lower cumulative gas production but a higher reservoir pressure and a higher flowing bottomhole pressure at the end of the stable period. Physically, a higher gas production rate induces a greater dynamic capillary pressure, while both cutoff water saturation and stress-induced permeability impose a similar impact on the dynamic capillary pressure, though the corresponding degrees are varied. Due to the dynamic capillary pressure, pseudo-mobile water saturation controlled by the displacement pressure drop also affects the gas production. The higher the gas production rate is, the greater the effect of dynamic capillary pressure on the cumulative gas production, formation pressure, and flowing bottomhole pressure will be. By taking the dynamic capillary pressure into account, it can be more accurate to predict the performance of a gas reservoir and the length of stable production period, allowing for making more reasonable development schemes and thus improving the gas recovery in a tight sandstone reservoir.

The Influence of Dynamic Capillary Pressure on the Seepage of Ultra-Low Permeability Reservoir

2014 ◽  
Vol 7 (1) ◽  
pp. 55-63 ◽  
Author(s):  
Haiyong Zhang ◽  
Shunli He ◽  
Chunyan Jiao ◽  
Guohua Luan ◽  
Shaoyuan Mo
Keyword(s):  
Capillary Pressure ◽  
Low Permeability ◽  
Low Permeability Reservoir ◽  
Dynamic Capillary Pressure

Dynamic capillary pressure during water infiltration: Experiments and Green-Ampt modeling

2012 ◽  
Vol 48 (6) ◽  
Author(s):  
Emanuele Pellichero ◽  
Roland Glantz ◽  
Meghan Burns ◽  
Debjani Mallick ◽  
Shao-Yiu Hsu ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Water Infiltration ◽  
Dynamic Capillary Pressure

Formation Characterization and Production Forecast of Tight Sandstone Formations in Daqing Oilfield Through Digital Rock Technology

2021 ◽  
Author(s):  
Danhua Leslie Zhang ◽  
Xiaodong Shi ◽  
Chunyan Qi ◽  
Jianfei Zhan ◽  
Xue Han ◽  
...  
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Surfactant Solution ◽  
Fluid Models ◽  
Pore Scale ◽  
Field Development ◽  
Digital Rock ◽  
Small Pore ◽  
Sem Imaging

Abstract With the decline of conventional resources, the tight oil reserves in the Daqing oilfield are becoming increasingly important, but measuring relative permeability and determining production forecasts through laboratory core flow tests for tight formations are both difficult and time consuming. Results of laboratory testing are questionable due to the very small pore volume and low permeability of the reservoir rock, and there are challenges in controlling critical parameters during the special core analysis (SCAL) tests. In this paper, the protocol and workflow of a digital rock study for tight sandstones of the Daqing oilfield are discussed. The workflow includes 1) using a combination of various imaging methods to build rock models that are representative of reservoir rocks, 2) constructing digital fluid models of reservoir fluids and injectants, 3) applying laboratory measured wettability index data to define rock-fluid interaction in digital rock models, 4) performing pore-scale modelling to accelerate reservoir characterization and reduce the uncertainty, and 5) performing digital enhanced oil recovery (EOR) tests to analyze potential benefits of different scenarios. The target formations are tight (0.01 to 5 md range) sandstones that have a combination of large grain sizes juxtaposed against small pore openings which makes it challenging to select an appropriate set of imaging tools. To overcome the wide range of pore and grain scales, the imaging tools selected for the study included high resolution microCT imaging on core plugs and mini-plugs sampled from original plugs, overview scanning electron microscopy (SEM) imaging, mineralogical mapping, and high-resolution SEM imaging on the mini-plugs. High resolution digital rock models were constructed and subsequently upscaled to the plug level to differentiate bedding and other features could be differentiated. Permeability and porosity of digital rock models were benchmarked against laboratory measurements to confirm representativeness. The laboratory measured Amott-Harvey wettability index of restored core plugs was honored and applied to the digital rock models. Digital fluid models were built using the fluid PVT data. A Direct HydroDynamic (DHD) pore-scale flow simulator based on density functional hydrodynamics was used to model multiphase flow in the digital experiments. Capillary pressure, water-oil, surfactant solution-oil, and CO2-oil relative permeability were computed, as well as primary depletion followed with three-cycle CO2 huff-n-puff, and primary depletion followed with three-cycle surfactant solution huff-n-puff processes. Recovery factors were obtained for each method and resulting values were compared to establish most effective field development scenarios. The workflow developed in this paper provides fast and reliable means of obtaining critical data for field development design. Capillary pressure and relative permeability data obtained through digital experiments provide key input parameters for reservoir simulation; production scenario forecasts help evaluate various EOR methods. Digital simulations allow the different scenarios to be run on identical rock samples numerous times, which is not possible in the laboratory.

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