Abstract:Oil–water relative permeability curve is an important parameter for analyzing the characters of oil and water seepages in low-permeability reservoirs. The fluid flow in low-permeability reservoirs exhibits distinct nonlinear seepage characteristics with starting pressure gradient. However, the existing theoretical model of oil–water relative permeability only considered few nonlinear seepage characteristics such as capillary pressure and fluid properties. Studying the influences of reservoir pore structures, c… Show more
“…To better understand this complex behavior, the relative permeability curves of all samples were corrected in this study, taking into consideration the slippage effect. The relative permeability curves for different types of pore-throat structures are presented in Figure , and the corresponding characteristic parameters are listed in Table , as shown in this paper …”
The pore-throat structure and gas–water seepage
behavior
are important factors affecting reservoir quality and development
efficiency. Sixteen tight sandstone samples from the He 8 and Shan
1 Formations in the Dingbian area of the Ordos Basin were analyzed
using casting thin section, scanning electron microscopy, high-pressure
mercury injection, and displacement experiments, integrated with the
nuclear magnetic resonance technique, to clarify the pore-throat structure
characteristics and their influence on the mobility of reservoir fluids.
The results revealed four characteristic pore-throat structure combinations:
large interparticle pore dominated pore-throat (LIPT), small interparticle
and dissolution pore dominated pore-throat (SIPT), intercrystalline
pore dominated pore-throat (IAPT), and nanopore dominated pore-throat
(NPT). Among these, IAPT and SIPT are identified as the main spaces
of movable fluids, and the number of IAPT and SIPT determines the
seepage capacity of the tight sandstone. The best fluidity was observed
in coarse-moderate sandstones in the riverine sedimentary phase with
high IAPT and SIPT, while the worst fluidity was observed in siltstones
in the NPT-dominated interfluvial bay phase. Linear correlation and
gray relational analysis were used to examine the quantitative effects
of nine factors on the flow of movable fluids with different pore-throat
combinations. Among these factors, the average pore-throat radius
exhibited the highest gray relational and weighting coefficient with
movable fluid saturation, with values of 0.81 and 0.12, respectively,
followed by the median radius and maximum mercury injection saturation.
In general, the average pore-throat radius size and connectivity are
key factors influencing the seepage behavior. Based on these findings,
seepage patterns of movable fluids with four different pore-throat
combinations were established in the context of the depositional environment.
This can help in better evaluating the heterogeneity of tight sandstones
and guide the exploration and development of tight oil and gas in
shallow braided river delta front sedimentary environments.
“…To better understand this complex behavior, the relative permeability curves of all samples were corrected in this study, taking into consideration the slippage effect. The relative permeability curves for different types of pore-throat structures are presented in Figure , and the corresponding characteristic parameters are listed in Table , as shown in this paper …”
The pore-throat structure and gas–water seepage
behavior
are important factors affecting reservoir quality and development
efficiency. Sixteen tight sandstone samples from the He 8 and Shan
1 Formations in the Dingbian area of the Ordos Basin were analyzed
using casting thin section, scanning electron microscopy, high-pressure
mercury injection, and displacement experiments, integrated with the
nuclear magnetic resonance technique, to clarify the pore-throat structure
characteristics and their influence on the mobility of reservoir fluids.
The results revealed four characteristic pore-throat structure combinations:
large interparticle pore dominated pore-throat (LIPT), small interparticle
and dissolution pore dominated pore-throat (SIPT), intercrystalline
pore dominated pore-throat (IAPT), and nanopore dominated pore-throat
(NPT). Among these, IAPT and SIPT are identified as the main spaces
of movable fluids, and the number of IAPT and SIPT determines the
seepage capacity of the tight sandstone. The best fluidity was observed
in coarse-moderate sandstones in the riverine sedimentary phase with
high IAPT and SIPT, while the worst fluidity was observed in siltstones
in the NPT-dominated interfluvial bay phase. Linear correlation and
gray relational analysis were used to examine the quantitative effects
of nine factors on the flow of movable fluids with different pore-throat
combinations. Among these factors, the average pore-throat radius
exhibited the highest gray relational and weighting coefficient with
movable fluid saturation, with values of 0.81 and 0.12, respectively,
followed by the median radius and maximum mercury injection saturation.
In general, the average pore-throat radius size and connectivity are
key factors influencing the seepage behavior. Based on these findings,
seepage patterns of movable fluids with four different pore-throat
combinations were established in the context of the depositional environment.
This can help in better evaluating the heterogeneity of tight sandstones
and guide the exploration and development of tight oil and gas in
shallow braided river delta front sedimentary environments.
“…Yan et al analyzed the relationship between the fractal dimension and pore structure based on fractal theory and MIP, exploring the fractal characteristics of reservoirs with different pore types . Su and Li proposed permeability calculation formulae that considered a fractal dimension. , Luo et al established a dual-medium permeability prediction model that considered fracture stress sensitivity based on the fractal dimension of the rock matrix and the tortuosity of the fracture aperture . As numerical simulation methods gradually became the mainstream method for quantitatively characterizing permeability, a numerical simulation based on micro-CT images can be used to construct a three-dimensional digital rock core reconstruction model, and then calculate its absolute permeability value through single-phase fluid simulation.…”
Due to the influence of a sedimentary environment, sandstone
characteristics,
diagenesis, and geological structure, the complexity and heterogeneity
of the pore structure in tight sandstone reservoirs act as key barriers
for accurate characterization of the influence of different pore microparameters
on reservoir physical properties. This paper obtained different scale
microscopic pore–throat parameters through mercury intrusion
porosimetry (MIP) and digital core reconstruction models. According
to the connectivity of different scale pores, connected pore structure
parameters, and pore fractal dimension, the pore structure characteristics
of tight sandstone reservoirs were evaluated. Subsequently, through
partial correlation analysis, the contribution rate of different scale
connected pore parameters to permeability and porosity was clarified.
Then, a multiparameter fitting equation for the absolute permeability
and porosity of the rock was obtained through multiple regression
analysis. The analysis results show that (1) the connected pores of
tight sandstone reservoirs are mainly mesopores, with the pore radius
distribution between 1 and 3 μm, and throat radius distribution
between 0 and 2 μm. (2) The complexity of the pore structure
in tight sandstone reservoirs is most strongly correlated with the
fractal dimension of the pore structure at the mesoporous scale. (3)
The pore radius and throat length at the mesoporous scale have the
strongest correlation with the absolute permeability of the rock,
and the pore radius at the mesoporous scale has the strongest correlation
with the porosity of the rock. (4) The multiparameter fitting equation
established by multiple regression analysis quantitatively and qualitatively
analyzed the impact of microscopic parameters of the pore–throat
structure at different scales on reservoir properties, achieving the
purpose of predicting the absolute permeability and porosity of the
tight sandstone reservoir. It provides guidance for the study of the
pore structure and permeability characteristics of tight sandstones.
“…Xie et al [5] established the seepage model of the multi-stage fractured horizontal well considering stress sensitivity and the starting pressure gradient in order to evaluate its productivity, and Li and Zhang [6] presented the production calculation model in consideration of variable starting pressure gradient in the ultra-low permeability reservoir. Ye et al [7] presented the fractal model for calculation of the starting pressure gradient considering the fractal dimension of the tight oil reservoir, and Su et al [8] built the analytical model for the permeability of oil and water in the lowpermeability reservoir based on the fractal theory for porous media. Ke et al [9] studied the effect of the starting pressure gradient on the remaining oil distribution in the heavy-oil reservoirs, and Tian et al [10] addressed the different factors that affect the starting pressure gradient in the tight sandstone gas reservoirs with high water saturation.…”
We consider a method for the determination of the starting pressure gradients of oil and water in two-phase flow in low-permeability reservoirs. Moreover, we obtain the relative permeability curves of oil and water according to water saturation for the interpretation of oil-water two-phase flow. In the case of two-phase Darcy flow in reservoirs, in order to obtain the relative permeability curves of oil and water according to water saturation, the JBN (Johnson, Bossler and Naumann) method is improved universally which is based on the analysis of data of two-phase unsteady displacement. The method may be improved in the case of low velocity non-Darcy flow in the low-permeability reservoirs, too. Therefore, in the context, we present a new method by which we can determine the starting pressure gradient of oil and water in two-phase non-Darcy flow in the low-permeability reservoirs. Based on these starting pressure gradients, we obtain relative permeability curves of oil and water according to water saturation by the process of data from two-phase unsteady displacement experiment using the Genetic Algorithm. In order to do for this, when oil and water flow simultaneously, the water content function in the condition of oil-water two-phase flow is obtained from the equations of motion of oil and water, and the equation of determining relative permeabilities using experimental data is presented. Based on this, the starting pressure gradients of oil and water are determined using search method of the Genetic Algorithm with powerful self-adaptability, and the curve of the relative permeability is plotted. The method can be improved effectively to determine the starting pressure gradients and relative permeabilities of oil and water in two-phase seepage in the low-permeability reservoirs and to study the numerical simulation and the reservoir engineering in these reservoirs.
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