Mercury Injection Methods Research Articles

Characteristics and pore evolution of the tight sandstone reservoirs of the Chang-7 Member of the Yanchang Formation in the Xin’anbian area, Ordos basin

More than 100 million tons of tight oil reserves have been discovered in the Xin’anbian area of the Ordos basin in recent years, of which the main reservoir is the Chang-7 Member of the Yanchang Formation. To identify the characteristics of the tight sandstone reservoir and their the development of the Chang-7 Member in the study area, casting thin sections, scanning electron microscopy (SEM), high-pressure mercury injection, cathodoluminescence and other technical methods were used to analyze the reservoir rock types and their physical properties and pore structure. Based on reservoir diagenesis research and quantitative evaluations of reservoir pores, a reservoir pore evolution mode was established. The results showed that the main rock types in the tight sandstone reservoirs in the Chang-7 Member of the Xin’anbian area were lithic feldspathic sandstone and feldspathic detritus sandstone and that the reservoir space types were mainly feldspar dissolved pores, with a few residual intergranular pores, clay intercrystalline pores, and microfractures. The reservoirs were classified as having low porosity and low permeability and extra-low porosity and extra-low permeability. The porosity and permeability of the reservoirs were between 4 ~ 10% and 0.01 ~ 1 mD, respectively, and were mainly controlled by compaction, cementation, and dissolution. Compaction and cementation reduced the porosity and permeability, while dissolution increased the porosity and permeability. The Chang-7 Member reservoir mainly experienced weak-medium compaction, medium-strong cementation, and different degrees of dissolution. The average loss of porosity due to cementation was around 25%, while the average loss due to compaction was around 13%. This research determined four key stages in the porosity evolution of the Chang-7 Member in the study area: (1) the porosity was reduced to 26% from the Triassic to the Early Jurassic period, which was mainly due to compression compaction; (2) the reservoir was seriously damaged by cementation from the Middle Jurassic to Late Jurassic period, where the porosity decreased to 5%; (3) in the Early Cretaceous period, the porosity increased to 11% due to dissolution; and (4) the porosity was reduced to 7% from the late Early Cretaceous to early Late Cretaceous period, which was mainly due to cementation.

A study on fractal characteristics of lacustrine shales of Qingshankou Formation in the Songliao Basin, northeast China using nitrogen adsorption and mercury injection methods

In order to research the fractal characteristics of lacustrine shale, we conducted low-pressure N2 adsorption and mercury injection measurements on 35 shale samples of Cretaceous Qingshankou Formation in the Songliao Basin, northeast China. The fractal dimensions (D1, D2, and D3) were obtained from N2 adsorption (P/Po < 0.5 and P/Po > 0.5) and mercury injection data, respectively. Accordingly, we analyzed the relationships between fractal dimensions and petrophysical and geochemical parameters. The results show that the fractal dimensions (D1, D2, and D3) are in the ranges of 2.0174–2.5705, 2.5589–2.8425, and 2.1461–2.9728, respectively. There exists a positive relationship between D1 and D2, suggesting that micropores and mesopores have similar surface characteristics. The poor correlations between D3 and D1 or D2 may be related to the different principles of low-pressure N2 adsorption and mercury injection. The fractal dimensions (D1 and D2) correlate positively with pore volumes and surface areas, which indicates that the fractal dimensions can well reflect the pore structure and surface characteristics. The fractal dimensions (D1 and D2) decreased with the increasing TOC content, which may be aroused by the low abundance of pores in organic matters. The fractal dimensions (D1 and D2) decreased firstly and then increased with the increasing maturity, which is aroused by liquid hydrocarbons generation and cracking. And the fractal dimension D3 decreased during maturation, which may be induced by compaction. The fractal dimensions (D1 and D2) decreased with the increasing Rock-Eval pyrolysis parameters S1 and S1/TOC, which suggests that the fractal dimensions can be indicators of oil content of shales.

TiO2/P(AM-co-AMPS) monolith prepared by CO2-in-water HIPEs and its potential application in wastewater treatment

Removing dyes and antibiotics from wastewater remains the current requirement for a global health problem. The ionic macroporous adsorbent is an efficient solution to this problem. Herein, a novel sulfonated TiO2/poly(acrylamide-co-2-acrylamido-2-methylpropanesulfonic acid) [TiO2/P(AM-co-AMPS)] macroporous composite monolith was first prepared by copolymerization of AM and AMPS in mTiO2-costabilized CO2-in-water Pickering high internal phase emulsions (HIPEs). The composite monoliths were characterized using XRD, SEM, confocal laser scanning microscopy, EDS mapping, FTIR, TGA, and mercury injection methods. The mechanical properties of the TiO2/P(AM-co-AMPS) HIPE were also evaluated. The void diameter could be adjusted by changing the density of carbon dioxide and the amount of mTiO2. The equilibrium swelling ratios of TiO2/P(AM-co-AMPS) with different contents of crosslinking agent of 2, 5, and 10 wt% (AM+AMPS) were 93, 37, and 19 g/g, respectively. TiO2/P(AM-co-AMPS) was used to remove methylene blue (MB) and tetracycline (TC) for evaluating the adsorptive properties of the composite monoliths. Results indicated that the main adsorption driving force was the electrostatic attraction between −SO3− and MB/TC. Adsorption experiments were conducted using a batch technique. The adsorption capacities of TiO2/P(AM-co-AMPS) for MB and TC were 1660 and 1128 mg/g in a wide pH range of 3–10. The equilibrium saturation point could be reached after 90 min for MB and 360 min for TC. Thereafter, the removal of MB and TC by gravity-driven separation was presented. The breakthrough curve and reuse evaluation for the removal of MB/TC were also studied in detail.

Microscopic pore structures of tight sandstone reservoirs and their diagenetic controls: A case study of the Upper Triassic Xujiahe Formation of the Western Sichuan Depression, China

Abstract The study of microscopic pore structures is of central significance to the evaluation of the reservoir quality and well productivity of tight gas sandstone. The second and fourth members (abbreviated as T3x2 and T3x4, respectively) of the Upper Triassic Xujiahe Formation of the Western Sichuan Depression were used as cases to analyze microscopic pore structures and diagenetic controls in consideration of the disparities in reservoir quality and well productivity. Optical microscopy of thin sections, Micro-CT Scanning, scanning electron microscopy (SEM), High Pressure Mercury Injection (HPMI) and apex methods based on the HPMI results were used to determine the pore and throat geometries and the types and pore size distributions in terms of the quantity and levels of pore connectivity. Tight sandstone reservoirs of the study area are characterized by poor physical properties, with the T3x2 reservoirs presenting relatively higher levels of permeability and lower porosity levels than those of the T3x4 reservoirs. The pore spacing configurations, sizes and distributions and throat geometries reveal significant disparities. Primary pores and micro-fractures were found to be more developed in the T3x2 reservoirs with bending and narrow pore throats measured as smaller than 0.5 μm. Compared to those of the T3x2 reservoirs, secondary pores including moldic and intracrystalline pores were more developed in the T3x4 reservoirs with relatively larger, straighter and wider throats of 0.5–1.0 μm. An evaluation of the pore connectivity levels shows that only 26.86% and 28.90% pores are closely connected to the whole for T3x2 and T3x4 reservoirs, respectively. Four major diagenetic processes were found to control reservoir quality and the microscopic pore structure. Mechanical compaction is the primary cause of the densification of reservoirs in the study area. Compared to that observed in the T3x4 reservoirs, more intensive mechanical compaction was observed in the T3x2 reservoirs, changing the configuration of the throats present, reducing the pore throat radii, and ultimately lowering the porosity of T3x2 reservoirs as a whole. Quartz overgrowth and late period carbonate cements were observed in partly filled pore spaces, narrowing throats and reducing pore connectivity, but eogenetic cementation and chlorite cements can increase the pressure-resistance of sandstone and inhibit compaction quartz overgrowth. Thus, T3x4 reservoirs are relatively more porous as a result of eogenetic calcite cementation, and primary pores are more developed in T3x2 reservoirs with chlorite cements. Dissolution is a major factor that improves the tight sandstone reservoir quality because it generates a large volume of secondary pores. The more intensive levels of dissolution in T3x4 reservoirs not only creates more intergranular, intragranular, moldic and intracrystalline pores but also further increases the porosity of T3x4 reservoirs. Fracturing effects have developed in the study area to improve pore connectivity levels and thus the permeability of tight sandstone reservoirs, potentially explaining the pore connectivity and permeability of certain T3x2 reservoirs. This work may be able to be used as a useful reference for the reservoir quality evaluation and exploration of tight gas sandstone reservoirs for similar oil fields worldwide.

Facile synthesis of Cu-BDC/Poly(N-methylol acrylamide) HIPE monoliths via CO2-in-water Emulsion stabilized by metal-organic framework

Macroporous poly(N-methylol acrylamide)–high internal phase emulsion [poly(NMA)HIPE] composite monoliths were prepared by carbon dioxide-in-water (CO2/W) emulsions using metal-organic framework (MOF) Cu-BDC (BDC = 1,4-dicarboxybenzene) as stabilizer. The composite monoliths were characterized using XRD, SEM, EDS-mapping, FT-IR, TG, and mercury injection methods. Increasing the internal phase fraction would lead to the decrease of monolith density and the increase of void size, and it is favorable for the formation of macroporous interconnected structure with low density and porosities up to 81.6%. The mechanical properties of the Cu-BDC/poly(NMA)HIPE and Cu-BDC removal were also evaluated. The composite polyHIPEs exhibited high antibacterial activity against Escherichia coli. The presented approach facilitated the clean manufacture of open-celled MOF based scaffolds in a one-pot process with porosity of up to 82%.

Irreducible water distribution from nuclear magnetic resonance and constant-rate mercury injection methods in tight oil reservoirs

Fifteen tight cores from Chinese Ordos basin were selected to obtain the irreducible water from fully-saturated by centrifuging with rotational speeds increased from 0 to 10,000 r/min, T2 spectra were measured by a low-field NMR core analysis unit concurrently. The fully-saturated T2 spectra showed a tri-modal pattern and ranged in 0~6, 6~100 and 100~1000 ms, which corresponded to micro-, meso- and macro- pore spaces, respectively. The irreducible water reached at the speed of 10,000 r/min with water saturation varied in 38.695~55.728%. Pore distributions by constant-rate mercury injection were adopted to get the transform coefficients between T2 time and pore-throat radius. SEM and thin sections were also introduced to support an intuitive understanding. It was found that irreducible water mainly remained in pores and throats ranged in 0.01~2 and 10~100 μm. The micro- pore spaces dominated by clay minerals, irregular microstructure and rough particles surface were considered to be dominantly effect factors. [Received: May 10, 2016; Accepted: February 2, 2017]

Irreducible water distribution from nuclear magnetic resonance and constant-rate mercury injection methods in tight oil reservoirs

Irreducible water distribution from nuclear magnetic resonance and constant-rate mercury injection methods in tight oil reservoirs

压汞法与气体吸附法联用分析沈352井致密储层岩石孔隙结构

油气储层孔隙直径分布研究的主要技术手段有压汞法、气体吸附法等。压汞法常用于测试连通的中孔和大孔的孔隙结构。氮气吸附法侧重于表征微孔和中孔的孔隙结构。仅靠一种方法不能给出孔结构的所有信息。因此，压汞法和气体吸附法相结合分析全孔隙结构特征尤为重要。本文将两种测试方法联用，分析沈352井致密储层岩石(油页岩、泥质泥晶云岩、云质泥岩)全孔隙结构的孔径分布特征，认为：油页岩中孔隙直径小于100 nm的占70%左右；孔隙直径呈现“三个峰”，第一个主峰为5~30 nm，次峰30~200 nm，第三个峰1000~3000 nm。泥质泥晶云岩中孔隙直径小于100 nm的占75%左右；孔隙直径略现“二个峰”，第一个主峰为2~30 nm，次峰50~100 nm。含云泥岩或云质泥岩中孔隙直径小于100 nm的占90%以上；孔隙直径以小于15 nm为主。 Mercury injection and gas absorption analytical methods are the main technical means of pore diameter distribution diagram of Petroleum Reservoir. Mercury injection method constantly is used for determination of connected middle pore and macropore, and gas absorption method is used for determination of Microporous and middle pore. Based on combination of mercury injection and gas absorption analytical methods, the complete pore diameter distribution diagram of tight reservoir rock can be obtained. By the use of the combination of two methods in tight reservoir rock of the well of shen352, the author makes a conclusion: Pore diameter which is less than 100 nm of oil shale is about 70%; it has “three peaks” at 5 - 30 nm, 30 - 200 nm and 1000 - 3000 nm. Pore diameter which is less than 100 nm of pelitic micrite dolomite is about 75%; it slightly presents “two peaks” at 2 - 30 nm, 50 - 100 nm. Pore diameter which is less than 100 nm of dolomitic mudstone is more than 90%; the main range of pore diameter of this rock is less than 15 nm.

Clastic Rock Physical Characteristics of Southern Songliao Basin Shiwu Fault Depression Layer

We sum up the reservoir space types and characteristics of clastic rock reservoir ShiWu fault depression rift layer study area, through core observation, microscope, scanning electron microscope and mercury injection methods, and discuss the development characteristics and formation mechanism of pore and fracture. A large number of core analysis, drill results and test mining research has confirmed that the study area is constructed by the strong force, the micro-cracks are well developed, it is not only important reservoir space, but also the flow of oil and gas wells to obtain high yield important seepage paths, is to obtain yield the necessary conditions.

A Comparison Between Mercury Injection and Nitrogen Sorption as Methods of Determining Pore Size Distributions

AbstractA comparison of mercury injection and nitrogen sorption methods of pore size distribution analysis was made on a sample of goethite using the slit‐shaped pore model. Using the commonly accepted contact angle of 140° for mercury, the mercury pore‐size distribution plot is displaced by approximately 20% in plate separation with respect to the nitrogen plot. The assumption of a contact angle of 153° for mercury is required to make the plots coincide. This value is regarded as not unrealistic. Combination of the two techniques provide a useful method of pore size distribution analysis over a continuous range of pore sizes from 10Å to 50µm. This approach is particularly appropriate to the investigation of the pore structure of soil materials.

Capillary Pressure Investigations

Abstract This paper presents results of static capillary pressure measurements madeboth by the restored-state and by the mercury-injection methods, and of dynamiccapillary pressure measurements made by the Hassler technique. The results indicate a variation from sample to sample of the factor used toconvert capillary pressure obtained by mercury injection to those applicable toa water-gas system. Static capillary pressures measured by the restored-statemethod were found to be in close agreement with dynamic capillary pressures, indicating that data obtained from static measurements may be utilized withconfidence in the solution of dynamic problems of fluid flow. Experimental data are presented on the use of "J-curves" for thecorrelation of capillary pressure-saturation relations for a number of coresfrom a particular geologic formation. It is shown that the correlation wasimproved in some cases by restricting it to certain lithologicclassifications. Introduction The Meaning and Importance of Capillary Pressure The coexistence of two or more immiscible fluids within the voids of aporous medium, such as reservoir rock, gives rise to capillary forces. Becauseof the interfacial tension existing at the boundary between two immisciblefluids in a pore space, the interface is curved, and there is a pressuredifference across the interface. This pressure difference is termed thecapillary pressure. The magnitude of the capillary pressure between two immiscible fluids whichtogether fill a porous medium depends upon several factors: the texturalproperties of the medium, the wettability of the medium, the interfacialtension between the fluids, the respective saturations of the fluids, and themanner in which these saturations are attained. For a given pair of immisciblefluids in a particular sample of reservoir rock, the capillary pressure is aunique function of the fluid saturation, provided that the saturation of thefluid which wets the rock has previously been decreased unidirectionally froman initially complete saturation. T.P. 3025