Pore Structure Characterization of Eocene Low-Permeability Sandstones via Fractal Analysis and Machine Learning: An Example from the Dongying Depression, Bohai Bay Basin, China
Abstract:Poroperm analysis,
mercury injection capillary pressure (MICP),
and nuclear magnetic resonance (NMR) measurements were performed to
delineate the pore structures and fractal behaviors of the Eocene
low-permeability sandstones in the Dongying Depression, Bohai Bay
Basin, China. Three types of pore structures (I, II, and III) have
been classified by applying the self-organizing map (SOM) clustering
model. Comparative analysis of three different fractal models indicates
that the MICP tubular model and NMR model a… Show more
“…An MI test was conducted using an automatic PoreMaster-33 mercury porosimeter. The maximum pressure of PoreMaster-33 was 33000 psi (227.57 MPa), corresponding to a minimum test aperture of 6.45 nm (Lu and Liu, 2021). The samples (irregular blocks with a side length of approximately 10-15 mm) were desiccated in a vacuum drying oven for 48 h and then loaded into the penetrometer to obtain the volume and pressure of mercury intrusion/extrusion.…”
In this study, X‐ray diffraction, N2 adsorption (N2A), and mercury intrusion (MI) experiments were used to investigate the influence of acid treatment on pore structure and fractal characterization of tight sandstones. The results showed that acid treatment generated a certain number of ink‐bottle pores in fine sandstone, aggravated the ink‐bottle effect in the sandy mudstone, and transformed some smaller pores into larger ones. After the acid treatment, both the pore volume in the range of 2–11 nm and 0.271–8 μm for the fine sandstone and the entire pore size range for the sandy mudstone significantly increased. The dissolution of sandstone cement causes the fine sandstone particles to fall off and fill the pores; the porosity increased at first but then decreased with acid treatment time. The fractal dimension obtained using the Frenkel‐Halsey‐Hill model was positively correlated with acid treatment time. However, the total fractal dimensions obtained by MI tests showed different changes with acid treatment time in fine sandstone and sandy mudstone. These results provide good guiding significance for reservoir acidification stimulation.
“…An MI test was conducted using an automatic PoreMaster-33 mercury porosimeter. The maximum pressure of PoreMaster-33 was 33000 psi (227.57 MPa), corresponding to a minimum test aperture of 6.45 nm (Lu and Liu, 2021). The samples (irregular blocks with a side length of approximately 10-15 mm) were desiccated in a vacuum drying oven for 48 h and then loaded into the penetrometer to obtain the volume and pressure of mercury intrusion/extrusion.…”
In this study, X‐ray diffraction, N2 adsorption (N2A), and mercury intrusion (MI) experiments were used to investigate the influence of acid treatment on pore structure and fractal characterization of tight sandstones. The results showed that acid treatment generated a certain number of ink‐bottle pores in fine sandstone, aggravated the ink‐bottle effect in the sandy mudstone, and transformed some smaller pores into larger ones. After the acid treatment, both the pore volume in the range of 2–11 nm and 0.271–8 μm for the fine sandstone and the entire pore size range for the sandy mudstone significantly increased. The dissolution of sandstone cement causes the fine sandstone particles to fall off and fill the pores; the porosity increased at first but then decreased with acid treatment time. The fractal dimension obtained using the Frenkel‐Halsey‐Hill model was positively correlated with acid treatment time. However, the total fractal dimensions obtained by MI tests showed different changes with acid treatment time in fine sandstone and sandy mudstone. These results provide good guiding significance for reservoir acidification stimulation.
“…High-pressure mercury intrusion technology is extensively used to determine the total pore volume and pore size distribution of reservoir rocks. 47 As shown in Figure 6A−C, the capillary force curves of mercury injection samples in the study area mostly conform to the types of II, IV, and V of six typical capillary force curves, 48 and the curve shape of different lithofacies is obviously different. The capillary pressure curves of TFC and PSS are mostly between II and V, which are characterized by an uneven middle section, poor pore sorting, and heterogeneous distribution of rock pore and throat but low mercury injection threshold pressure.…”
Section: Grain Size Distribution and Petrological Characteristics The...mentioning
confidence: 80%
“…High-pressure mercury intrusion technology is extensively used to determine the total pore volume and pore size distribution of reservoir rocks . As shown in Figure A–C, the capillary force curves of mercury injection samples in the study area mostly conform to the types of II, IV, and V of six typical capillary force curves, and the curve shape of different lithofacies is obviously different.…”
The pore structure
and movable fluid characteristics of tight conglomerate
reservoirs are complex, which are greatly different from conventional
reservoirs. The depositional mechanism is the fundamental factor controlling
the physical properties of conglomerate reservoirs. However, there
is a lack of systematic research on the pore structure and movable
fluid characteristics of conglomerate reservoirs with typical sedimentary
facies. This paper investigates the pore structure and movable fluid
characteristics of conglomerate of different sedimentary facies based
on various experiments. Casting thin sections, X-ray diffraction,
scanning electron microscopy, high-pressure mercury injection, and
nuclear magnetic resonance experiments were conducted on 32 conglomerates
samples from the Mahu Sag, Junggar Basin, China. The quality classification
method of tight conglomerate reservoirs is established. The results
show that the conglomerate can be divided into three sedimentary facies;
traction flow conglomerate (TFC) and pebbled sandstone (PSS) mainly
develop intergranular pores and dissolved pores; and the pore diameter
curves are mainly a double peak, single peak, and flat peak. Gravity
flow conglomerate (GFC) mainly develops dissolved pores and interstitial
micropores, and the pore diameter curve is mainly a single peak. PSS
includes pebbled gritty sandstone (P(G)SS) and pebbled fine sandstone
(P(F)SS). TFC and P(G)SS are favorable class I reservoirs, while GFC
and P(F)SS are nonfavorable class II reservoirs. A new parameter,
the ratio of the major axis to the minor axis of the pore outer ellipse
(axial ratio), is proposed to quantitatively describe the compaction
effect. The average axial ratios of the three lithofacies are 3.04,
3.98, and 8.78, respectively, indicating that the compaction is intensified
and the pore structure becomes worse. By analyzing the correlation
between pore structure parameters and permeability, it is found that
the main controlling factors of permeability of GFC and TFC are sorting
and connectivity, respectively, and the main flow radius is the most
suitable parameter to describe permeability. A linear spectral decomposition
method was used to establish a new quantitative calculation method
of movable fluid saturation for different types of pores, and the
results show that the movable fluid saturation of intergranular pores
is the highest (average: 65.43%), and the movable fluid saturation
of TFC and P(G)SS with more intergranular pores is the highest. Movable
fluid saturation is inversely proportional to the content of I/S and
the compaction rate and positively proportional to the content of
quartz and feldspar and the cementation rate. The fluid mobility of
water-wet samples is weaker. The research results provide theoretical
support for the identification of favorable reservoirs and the cognition
of a development mechanism.
“…The physical properties of the reservoir are mainly affected by the original sedimentary and diagenetic processes (Liu et al, 2016;Zhu et al, 2017;Lu and Liu, 2021), among which, the sedimentary mechanism was the most important. Specifically, the original sedimentary environment and mechanism determine the material basis of the reservoir, while the subsequent geological processes only modify it.…”
Section: Influence Of Original Sedimentary Environment On Reservoir Q...mentioning
Shahejie marl in the Shulu Sag is a crucial resource for unconventional hydrocarbon exploration in China. Although breakthroughs have been made in tight oil exploration in this area, the mechanisms underlying the formation of this marl reservoir and factors controlling its ‘sweet spots’ have not been thoroughly studied. To understand the pore structure characteristics and factors influencing the marl reservoir, we analyzed core samples from Wells ST1 and ST3. A series of experiments was conducted on the samples, such as X-ray diffraction, focused ion beam scanning electron microscopy, micro-CT, and total organic carbon test. Additionally, the physical properties of different marl rock fabrics were studied with auxiliary tests, such as mercury intrusion capillary pressure analyses, nuclear magnetic resonance, porosity and permeability tests, and thin-section observation. The results revealed that the marl reservoir is characterized by low porosity (1.61%) and low permeability (2.56mD). The porosity and permeability (1.61% and 3.26mD) of laminated marl were better than those (0.92% and 1.68mD) of massive marl. Clay minerals and quartz content in laminated (11.8 and 8.2%) was less than in massive marl (16.2 and 13.3%). The marl pores include intercrystalline pores, dissolution pores, and microfractures. Additionally, the laminated marl pores were primarily distributed along the dark lamina, with good connectivity. A few isolated and uniform holes were observed in the massive marl. Influenced by rock fabric and mineral composition, layered fractures were mainly developed in the laminated marl, while structural fractures were the main type of microfractures in the massive marl. The primary sedimentary mechanism was the main geological action underlying the differences in marl rock fabric; this mechanism affects the physical properties of the marl reservoir, which are key factors to be considered when searching for the marl reservoir ‘sweet spots’. Particular attention should be paid to these factors during tight oil exploration and development in similar sedimentary basins.
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