Mercury Injection Measurements Research Articles

Experimental study of oil recovery mechanisms during imbibition in tight sandstone with different fluid displacing agents under ambient and reservoir pressure

This study explores oil recovery mechanisms of static imbibition in a tight sandstone under different imbibition pressures, simultaneously optimizing imbibition agents. To this end, the static imbibition experiments of two common agents, polyacrylamide (PAM) slick water and anion–nonionic surfactants, are conducted under atmospheric and reservoir pressure (20 MPa). The interfacial tension and contact angle of these two imbibition fluids are also measured. Herein, the entire recovery period and imbibition equilibrium time vs. pressure are determined. Based on NMR and high-pressure mercury injection measurements, the contributions of pores with different sizes to the displacement recovery during imbibition are quantified. Under atmospheric pressure, the recovery rate with the surfactant was measured higher than that of the PAM slick water. The main reason was that the former has a lower interfacial tension (0.0961 mN/m), stronger hydrophilicity (average contact angle 27.7°), and stronger oil-displacing effect. Under a reservoir pressure of 20 MPa, the surfactant had lower recovery rate than the PAM slick water, while the latter enhanced the recovery further. Under atmospheric pressure, both agents recovered the crude oil in the medium-sized and larger pores whereas, under reservoir pressure (20 MPa), they mainly recovered oil from the smaller and medium-sized pores. At higher imbibition pressures, both agents recovered more oil from the smaller and medium-sized pores, and less from micropores and larger pores. This indicated that higher pressures can further improve the driving force of fluid replacement, to improve oil production from finer and medium-sized pores significantly. Under atmospheric pressure, both agents reached imbibition equilibrium in approximately 20 days while this period was reduced for the surfactant and slick water to 16 and 12 days, respectively. Based on the results PAM slick water is recommended for EOR purposes in tight sandstone which can be generalized to similar formations around the globe.

Geophysical pore type inversion in carbonate reservoir: Integration of cores, well logs, and seismic data (Yadana field, offshore Myanmar)

Detection of pore types and diagenetic features from seismic data is a major challenge for the evaluation of carbonate reservoirs in the subsurface. Based on a detailed petrographical and petrophysical analysis of carbonate rock using optical and scanning electron microscopy, mercury-injection measurements, digital image analysis, and well logs, we have determined the potential of the geophysical pore type ([Formula: see text]) inversion — a rock physics inversion scheme based on the differential effective medium theory—to quantitatively and qualitatively characterize the pore type distribution from acoustic data in the Yadana carbonate gas field (Early Miocene, offshore Myanmar). The geophysical pore type ([Formula: see text]) is revealed to be an upscalable parameter, whose depositional/diagenetic interpretation may be performed at well log and at seismic scales. We apply the inversion method on a 3D seismic data to map the reservoir-scale distribution and highlight the occurrence of laterally extended (100–1000 m) subseismic- to seismic-scale (thickness [Formula: see text]) geologic bodies. From this approach, two main reservoir geobodies are discriminated and interpreted in terms of depositional and diagenetic fabrics: (1) highly microporous, decameter-scale reservoir units (approximately 80% of the reservoir), mainly consisting of foraminiferal, red algae floatstone to rudstone with vuggy moldic porosity and characterized by moderate to high [Formula: see text] (0.11–0.20) and (2) thin, stratiform, cemented scleractinian floatstone/brecciated units (5–10 m; approximately 20% of the reservoir) with low microporosity and macroporosity and exhibiting low [Formula: see text] values ([Formula: see text]).

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.

Determination of the critical flow pore diameter of shale caprock

Abstract The breakthrough pressure and pore permeability characteristics of shale caprock are the physical response of the microscopic pore throat structure. Whether oil and gas can break through shale caprock under the action of migration force is closely related to the critical flow pore diameter (pore throat diameter) of the rock. Therefore, the critical flow pore diameter is a key parameter for the division of the reservoir and caprock and evaluation of the physical seal abilities of caprock, affecting the oil and gas migration and accumulation, which are controlled by the critical lithology. In this study, the shale caprock of the N gas reservoir of the Huagang Formation in the Xihu sag, East China Sea Basin was comprehensively studied using particle size analysis, systematic environmental scanning electron microscopy, nano-CT, digital core reconstruction, low-temperature gas adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance test for unconventional reservoir. In addition, the critical flow pore diameter of the shale caprock was determined. Based on the intersection point of the trendline of the breakthrough pressure data between the caprock and reservoir and the lower breakthrough pressure limit of the caprock of the gas–water reservoir, the breakthrough pressure limit of the caprock and reservoir is 2 MPa. Based on the correlation between the breakthrough pressure and shale lithology, the critical lithology for the division of the caprock and reservoir is argillaceous siltstone with a low breakthrough pressure limit of 2 MPa. Based on the identification of lithology boundary between caprock and reservoir, the critical lithology of the argillaceous siltstone selected as the research object, above-mentioned unconventional reservoir test technologies were carried out. The pore size statistics obtained from environmental scanning electron microscopy and the digital core model show that the critical flow pore diameter is between 100 and 300 nm. The high-pressure mercury injection test shows that the critical flow pore diameter ≥155 nm. The full pore diameter distribution curve is obtained by combined low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption and high-pressure mercury injection measurements. Compared the full pore diameter distribution curve with the nuclear magnetic resonance T2 spectrometry before and after centrifugation, the critical flow pore diameter is greater than 84 nm, ranging between 148 and 339 nm. Finally, based on the lithology, breakthrough pressure, and pore diameter relationships, the critical flow pore diameter of the shale caprock is 200 nm.

A fractal model for threshold pressure gradient of tight oil reservoirs

In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (η0), pore throat fractal dimension (Df), tortuosity fractal dimension (DT), the maximum pore radius (rmax), the characteristic length of the core (L0), and the connate water saturation (Swi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001–0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher Swi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.

Stress Sensitivity of Mercury-Injection Measurements

Many petrophysical properties (e.g. permeability, electrical resistivity etc.) of tight rocks are very stress sensitive. However, most mercury injection measurements are made using an instrument that does not apply a confining pressure to the samples. Here we further explore the implications of the use and analysis of data from mercury injection porosimetry or mercury capillary pressure measurements (MICP). Two particular aspects will be discussed. First, the effective stress acting on samples analysed using standard MICP instruments (i.e. Micromeritics Autopore system) is described. Second, results are presented from a new mercury injection porosimeter that is capable of injecting mercury at up to 60,000 psi into 1.5 or 1 in core plugs while keeping a constant net stress up to 15,000 psi. This new instrument allows monitoring of the electrical conductivity across the core during the test so that an accurate threshold pressure can be determined. Although no external confining pressure is applied (unconfined) when using the standard MICP instrument, this doesn’t mean that the measurements can be considered as unstressed. Instead, the sample is under isostatic compression by the mercury until it enters the pore space of the sample. As an approximation, the stress that the mercury places on the sample is equal to its threshold pressure. Thus, the permeability calculated from standard MICP data is equivalent to that measured at its threshold pressure. Not all the samples have the same stress dependency thus comparing measured permeabilities at a single stress with values calculated from standard MICP data, corresponding at different threshold pressures, can lead to erroneous correlations. Therefore, the estimation of permeabilities from standard MICP data can be flawed and uncertain unless the stress effect is included. Results obtained from the new mercury injection system, porosimeter under net stress, are radically different from those obtained from standard MICP instruments such as the Autopore IV. In particular, the measurements at reservoir conditions produce threshold pressures that are three times higher and pore throat sizes that are 1/3rd of those measured by the standard MICP instrument. The results clearly indicate that calculating capillary height functions, sealing capacity, etc. from the standard instrument can lead to large errors that can have significant impact on subsurface characterization.

Permeability prediction from mercury injection capillary pressure: an example from the Perth Basin, Western Australia

For shale gas reservoirs, permeability is one of the most important and difficult parameters to determine. Typical shale matrix permeabilities are in the range of 10 microdarcy–100 nanodarcy, and are heavily dependent on the presence of natural fractures for gas transmissibility. Permeability is a parameter used to measure the ability of a rock to convey fluid. It is directly related to porosity and depends on the pore geometry features, such as tortuosity, pore shape and pore connectivity. Consequently, rocks with similar porosity can exhibit different permeability. Generally, permeability is measured in laboratories using core plugs. In some cases, however, it is difficult to obtain suitable core plugs. In these instances, other approaches can be used to predict permeability, which are chiefly based on mathematical and theoretical models. The approach followed in this peer-reviewed paper is to correlate permeability with capillary pressure data from mercury injection measurements. The theoretical and empirical equations, introduced in the literature for various conventional and unconventional reservoir rocks, have been used to predict permeability. Estimated gas shale permeabilities are then compared with results from transient and steady state methods on small pieces of rocks embedded in a resin disk. The study also attempts to establish a suitable equation that is applicable to gas shale formations and to investigating the relationship between permeability and porosity.

Estimation of Saturation Exponent from Nuclear Magnetic Resonance (NMR) Logs in Low Permeability Reservoirs

The resistivity experimental measurements of 36 core samples, which were drilled from low permeability reservoirs of southwest China, illustrate that the saturation exponents are not agminate, but vary from 1.627 to 3.48; this leads to a challenge for water saturation estimation in low permeability formations. Based on the analysis of resistivity experiments, laboratory nuclear magnetic resonance (NMR) measurements for all 36 core samples, and mercury injection measurements for 20 of them, it was observed that the saturation exponent is proportional to the proportion of small pore components and inversely proportional to the logarithmic mean of NMR T2 spectrum (T2lm). For rocks with high proportion of small pore components and low T2lm, there will be high saturation exponents, and vice versa. The proportion of small pore components is characterized by three different kinds of irreducible water saturations, which are estimated by defining 30, 40 and 50 ms as T2 cutoffs separately. By integrating these three different kinds of irreducible water saturations and using T2lm, a technique of calculating the saturation exponent from NMR logs is proposed and the corresponding model is established. The credibility of this technique is confirmed by comparing the predicted saturation exponents with the results from the core analysis. For more than 85 % of core samples, the absolute errors between the predicted saturation exponents from NMR logs and the experimental results are lower than 0.25. Once this technique is extended to field application, the accuracy of water saturation estimation in low permeability reservoirs will be improved significantly.

Petrophysical and petrochemical effects of long-term CO2 -exposure experiments on brine-saturated reservoir sandstone

Sandstone samples of the Stuttgart Formation at Ketzin have been experimentally treated with CO2 and synthetic reservoir brine in high-quality steel autoclaves at simulated in situ P-T conditions of 5.5 MPa and 40 °C. In order to observe mineralogical changes induced by CO2, untreated samples are compared to CO2-treated ones. Samples show a comparable petrography of mainly quartz and plagioclase. Heterogeneities are related to minor mineral phases, such as K-feldspar, hematite, muscovite, biotite, illite, chlorite, and opaque phase(s). This variability of the Stuttgart Formation is primarily attributed to the sandstone sedimentation in a meandering, fluvial environment. The samples are weakly consolidated. Analcime, anhydrite and dolomite are only found as cement phases. SEM micrographs of CO2-treated samples show corrosion textures on mineral surfaces of anorthitic plagioclase and K-feldspar, as well as euhedral albite crystals. Overall, the data indicate preferred dissolution of calcium-rich plagioclase, K-feldspar and anhydrite, and stabilization or precipitation of albite. The petrophysical properties of the sandstone samples also show slight changes. Nuclear magnetic resonance (NMR) and mercury injection measurements indicate a slightly increased porosity and a shift to larger pore sizes; both suggesting dissolution processes.

Determining pore‐throat size in Permo‐Triassic sandstones from low‐frequency electrical spectroscopy

Hydraulic conductivity or permeability, a knowledge of which is vital in modelling the movement of hydrocarbons in reservoir rocks and contaminants in aquifers, is strongly related to the intergranular pore‐throat size in sandstones. For many years attempts have been made to determine permeability from the electrical properties of rocks, but with little success. Here we have measured the complex electrical conductivity of Permo‐Triassic sandstone samples over the frequency range 0.0001–1000 Hz and show how parameters determined from the characteristic shape of the spectra correlate closely to pore‐throat size determined from mercury injection measurements.

Porosity microstructures of a sandstone affected by a normal fault

Normal faults are part of the elements that control fluid flows in sedimentary basins. They can play the role of a barrier or a drain [Hippler, 1993]. These pathways are anisotropic. The aim of this study is to determine the fluid pathways and to characterise the pore network and its role in the transfer properties. Petrophysics, petrographics, geochemical and fluid inclusion studies allow us to characterise a Buntsandstein sandstone affected by a normal fault. This sandstone has a fluviatile origin, field evidenced by fluviatile channels, but also by some clay layers. The fault is located in the north east of France, in the Rhine Graben. The vertical displacement is about 3 meters, and the dip is 70o east. The fractured zone is composed of three compartments (the hanging wall and the footwall separated by a gouge) divided by three main faults (fig. 1). Oriented samples were taken from the three blocks and were studied following the procedure figure 2.

Permeability Prediction from Geologic Models

Permeability is a critical parameter for the petroleum geologist. By simulating the processes of compaction and cementation in a model porous medium, we have gained a new understanding of how permeability is controlled in reservoir sandstones. This understanding can be used predictively for simple sandstones. The geometry of the model pore system is completely defined, so permeability can be calculated directly using a network model for flow. The calculation is based on first principles and is physically rigorous. In contrast to many previous efforts to predict permeability, there are no adjustable parameters in the calculations and no additional measurements or correlations (e.g., capillary pressure data or pore system data from thin sections) are required. The model-derived porosity-permeability trend for a compacted or quartz cemented sandstone, or a sandstone having a combination of these processes, closely matches measurements on Fontainebleau sandstone samples whose permeabilities span nearly five orders of magnitude. The model also correctly predicts mercury injection measurements of pore throat size distribution for the Fontainebleau sandstone. Pore-scale geometric features of the model are found to be spatially correlated, and this departure from randomness significantly affects macroscopic properties such as permeability. The agreement between predictions and measurements suggests that spatial correlation is inherent in granular porous media and consequently, uncorrelated (or arbitrarily correlated) models of transport in such media are unlikely to be physically representative. We also discuss extending the model to predict properties of more complicated rocks.

Mercury injection measurements used in the prediction of rock pore dimensions employing a crystalline lattice of capillaries

One method used to investigate the pore structure of a rock sample is to obtain a mercury injection curve. The resulting plot shows the volume of mercury introduced into the sample as the applied pressure is increased. It is assumed here that the occupied pores are cylinders with diameters selected from a normal distribution. The rapid estimation of appropriate parameters for this distribution may be performed graphically or by substituting into polynomial approximations. It is not essential to plot the injection curve, the only measures needed being the first two normalized moments of the raw data.

Prediction of rock electrical conductivity from mercury injection measurements

We show that mercury injection can be used to characterize the portions of rock pore space that dominate both the electrical conductivity and the absolute permeability. The resulting new expression for the conductivity formation factor is fundamentally different from the classical Archie's law but will appear similar to it in some circumstances. The predictions of our theory for both conductivity and permeability agree with the experimental measurements within expected errors. The results indicate that the absolute permeability and the conductivity formation factor can be predicted from mercury injection measurements with no adjustable parameters.