Low-permeability Samples Research Articles

Heterogeneity dynamics: influencing rock type responses to overburden pressure, Permian–Triassic of the Persian Gulf

This study considers the impact of reservoir pressures on rock type variations within the Permian–Triassic formations in the Persian Gulf. Lithological composition, textures, visible porosity, pore types, and cementations of 328.85 m of carbonate rocks from Kangan and Dalan formations were determined using a polarizing microscope. Porosity, permeability, and rock types were analyzed under ambient and reservoir pressures. Findings showed limestone’s frequent rock type changes under reservoir pressure via the Winland method, while dolomite samples showed significant alterations using the flow zone indicator method. Grainstones predominated overall, persisting even amidst pressure-induced rock type shifts, indicating texture’s minimal influence. Pore throat size of low porosity samples rapidly decreased under reservoir pressure, leading to substantial rock type changes. Fewer alterations were observed based on permeability-to-porosity ratio via the flow zone indicator method. Additionally, low permeability samples exhibited varied rock types under the Winland method, while flow zone indicator method transitions mainly occurred within specific permeability ranges. In essence, this study offers a detailed understanding of pressure’s intricate interplay with rock types and properties in Persian Gulf carbonate reservoirs.

Pore-Scale Experimental Investigation of the Residual Oil Formation in Carbonate Sample from the Middle East

Select porous carbonate cores are used to carry out water-flooding oil micro-CT flooding experiments, and use image processing to separate oil, water, microfacies, and rock skeleton. The gray value is used to determine the distribution position of the microfacies sub-resolution remaining oil. The gray image resolution is improved by the SRCNN method to improve the pore identification accuracy. The distribution and evolution law of the sub-resolution remaining oil after the displacement is determined by the oil-water distribution results. Using the SRCNN method, the pore recognition accuracy of the original scanned images of the two samples was increased by 47.88 times and 9.09 times, respectively. The sub-resolution residual oil and the macro-pore residual oil were determined from the CT scan images after the brine was saturated and divided into five categories. With the increase in the displacement ratio, the columnar and droplet residual oil of the low-permeability samples first increased and then decreased, and the cluster residual oil gradually decreased. The continuous residual oil of the hypertonic samples gradually decreased, and the discontinuous residual oil gradually increased. According to the research results of carbonate pore throat identification and sub-resolution microscopic residual oil change characteristics after water flooding under the SRCNN method, a method for distinguishing porous carbonate reservoirs is provided.

Effect of pressure pulse stimulation on imbibition displacement within a tight sandstone reservoir with local variations in porosity

The pressure pulse technique has been suggested as a potential method to enhance oil recovery from tight oil reservoirs. To investigate the variations in the pore structure of tight sandstone samples from the Triassic Yanchang Formation in the Ordos Basin (China), a combination of casting thin sections, high-pressure mercury intrusion, and nuclear magnetic resonance was employed. Imbibition experiments combined with the imposed pressure pulse were performed to quantitively examine the effects of the primary parameter relevant to pressure pulse on displacement efficiency and oil recovery contribution of the various pore systems. By testing the effect of different pulse pressures, it was investigated which mechanisms controlled the oil recovery. It was thus found that a series of four pulses could enhance the oil recovery significantly, and that the pressure should be 2 MPa，4 MPa and 6 MPa for the three investigated types of reservoirs, respectively. In these cases, their corresponding pulse times are 48 h, 96 h, and 144 h, respectively. The oil displacement efficiency increases with the increasing pressure and pulse cycles; however, the amplitude in oil recovery gradually diminishes. It was also found that an increasing pulse pressure is favorable for mobilizing oil that is trapped in pore spaces, especially for the low-permeability samples, despite the longer pulse time. Employing the pressure pulse method could markedly improve the imbibition oil recovery, and the simultaneous pulse pressure with imbibition leads to a higher oil recovery than the approach that adopts the pulse pressure after imbibition experiments. The main cause is that the former method facilitates oil recovery, particularly from intermediate-sized pores in relatively porous media. Furthermore, there is a significant difference in oil displacement within the various pore systems for the various types of reservoirs. The developed microfractures greatly contribute to oil recovery during the early imbibition stage, and the pressure pulse method appears most suitable to tight reservoirs with a relatively uniform pore size distribution and a higher proportion of medium-large pores.

Gas relative permeability evaluation in tight rocks using rate-transient analysis (RTA) techniques

The evaluation of effective and relative gas permeability is critical for modeling hydrocarbon recovery from low-permeability (unconventional) reservoirs, and for evaluating the potential for clean energy pathways such as carbon capture and sequestration and hydrogen storage in subsurface. Nevertheless, due to the low flow rates and long experimental times associated with low-permeability (nanodarcy/microdarcy range) sample testing, measuring relative permeability through conventional techniques is technically challenging, time-consuming, and expensive. Additionally, and importantly, none of the routine laboratory techniques for measuring relative permeability can mimic the boundary conditions under which wells are produced from, or injected into, in the field.For the first time, effective and relative gas permeability of partially-saturated low-permeability sedimentary rocks were investigated using state-of-the-art core analysis techniques based on rate-transient analysis (RTA). Conventional and new straight-line analysis methods, commonly applied to production data in the field, were used to estimate effective gas permeability of core plugs under variable stress conditions and water saturations. Five low-permeability siltstone and organic/clay-rich samples, differing in mineralogy, porosity, and pore size distribution, were analyzed for proof-of-concept testing.The observed flow regimes consist of transient linear flow followed by boundary-dominated flow regimes, as previously reported for field data. Satisfactory correlation (average coefficient of variation less than 7%) between permeability estimates using different RTA techniques demonstrates the applicability of this method for effective and relative permeability assessment of partially-saturated ultra-tight reservoirs (down to less than 1.0∙10−5 md). Importantly, test times after the initiation of the production phase, were on the order of minutes, which is significantly shorter than those commonly achievable using conventional techniques (e.g., hours using pulse-decay gas permeability testing). Effective gas permeability (from 1.5∙10−3 to 7.5∙10−6 md), and slip factor (from 715 to −286 psia−1), decreased with increasing water saturation (0–53%), reflecting the lower contribution of slip flow to gas transport. Effective gas permeability decreased with increasing effective stress (500–4000 psia), likely due to reduced effective (transport) pore throat size and increased tortuosity. The reduction of slip factor and the observed stress dependency with water saturation is attributed to the channel flow mechanism.

Carbonated Water Injection Effects on Lacustrine Carbonates of Mupe Member, Lower Purbeck Group (Upper Jurassic), United Kingdom

Summary This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.

Obtaining capillary pressure curves from resistivity measurements in low-permeability sandstone

The increasing global demand for energy necessitates exploring and developing low-quality prospects, e.g., low-permeability reservoirs, which contain substantial hydrocarbon resources and have the potential to fill the gap in the energy markets. Typically, modeling fluid flow using reservoir simulators requires capillary pressure curves as an input. Nonetheless, laboratory capillary pressure measurements in low-permeability samples are time-consuming and challenging. On the contrary, resistivity measurements are easier to perform in the laboratory and offer a different prospect for obtaining capillary pressure curves. This paper proposes a new approach for obtaining capillary pressure curves from resistivity measurement in low-permeability sandstone using fractal theory and genetic algorithm. First, the fractal pore system is characterized as tortuous square and triangular capillaries to account for angular pores. Afterward, the drainage process is simulated to develop an innovative electrical resistivity model in fully and partially saturated porous media. Next, the genetic algorithm matches laboratory-measured resistivity data and obtains the developed model parameters. Afterward, the matched parameters are adopted in the drainage capillary pressure model to generate capillary pressure curves. The proposed model's reliability is verified by analyzing the prediction results of eighteen sandstone core samples. Furthermore, the developed model performance is compared with different models from the literature, and the results indicated its superiority in predicting capillary pressure curves.

Displacement efficiency and storage characteristics of CO2 in low permeability reservoirs: An experimental work

Over the past decades, CO2 flooding in low-permeability porous media has continued to grow. Furthermore, propelled by the current movement toward CO2 sequestration, the flooding of CO2 is expected to further increase. Thus, it is of scientific significance to study the mechanism of displacement of CO2 flooding as well as the CO2 storage characteristics. In this study, CO2 miscible/immiscible flooding experiments were conducted on two low permeability samples to study the difference between them. Specifically, the effect of oil displacement and CO2 storage coefficient for different displacement models were measured and compared. In addition, nuclear magnetic resonance (NMR) tests and frozen pelleting experiments were conducted. The NMR tests clarified the lower limit of pore throat where oil can be displaced by CO2 miscible/immiscible flooding. Furthermore, the frozen pelleting experiments analyzed the distribution characteristics of the remaining oil before and after CO2 miscible/immiscible flooding. The investigation showed that the development efficiency of CO2 miscible flooding is higher than CO2 immiscible flooding in low permeability reservoirs. The results also indicated that CO2 miscible flooding increases the recovery of hard-to-produce semi-bound oil phase and CO2 storage coefficient with CO2 miscible displacement is more significant than that with CO2 immiscible flooding. The data from this study is a critical input for reservoir simulation, which sheds light on the CO2 miscible/immiscible flooding in low permeability reservoirs.

Prediction of permeability of tight sandstones from mercury injection capillary pressure tests assisted by a machine-learning approach

Mercury injection capillary pressure analysis is a methodology for determining different petrophysical properties, including bulk density, porosity, and pore throat distribution. In this work, distinct parameters derived from mercury injection capillary pressure tests was considered for the prediction of permeability by coupling machine learning and theoretical approaches in a dataset composed of 246 tight sandstone samples. After quality checking the dataset, the feature selection was carried out by correlation analysis of different theoretical permeability models and statistical parameters with the measured permeability. Finally, porosity, median capillary pressure, Winland model, and mean pore-throat radius (corresponding to the saturation range 0.4-0.8) were chosen as the input features of the machine learning model. As the machine learning approach, a support vector machine (SVM) model with a radial basis function kernel was proposed. Furthermore, the model and its metaparameters were trained with a particle swarm optimization (PSO) algorithm to avoid over-fitting or under-fitting. In contradiction to the theoretical models, the implemented SVM-PSO model could acceptably predict the experimentally measured permeability values with an R2 rate of over 0.88 for training and testing datasets. The introduced approach could reduce the mean relative errors from about 10 to values less than 0.45. The improvements were more significant for low permeability samples. This successful implementation shows the potential of coupled usage of theoretical and machine learning methodologies for improved prediction of permeability of tight sandstone rocks. Cited as: Abbasi, J., Zhao, J., Ahmed, S., Jiao, L., Andersen, P., Cai, J. Prediction of permeability of tight sandstones from mercury injection capillary pressure tests assisted by a machine-learning approach. Capillarity, 2022, 5(5): 91-104. https://doi.org/10.46690/capi.2022.05.02

An experimental investigation of improving Wolfcamp Shale-Oil recovery using Liquid-N2-assisted N2 and/or CO2 Huff-n-Puff injection technique

Despite drilling numerous horizontal-hydraulically-fractured wells in unconventional reservoirs, the oil recovery factor (RF) of such reservoirs is still very low (<10%), leaving behind massive unrecovered oil in the formation. Improving the oil RF of unconventional reservoirs requires applying and developing enhanced oil recovery techniques. In this study, the feasibility of improving Wolfcamp shale oil RF using liquid nitrogen (LN2) combined with three cycles of N2 and/or CO2 huff-n-puff injections at reservoir temperature (77 °C) and different injection pressures was investigated. The results revealed that LN2-assisted N2 and/or CO2 huff-n-puff injections improved the Wolfcamp oil RF, outperforming the current-experimental practice of N2, CO2, or natural-gas huff-n-puff injections. Higher oil RFs with less soaking time and fewer cycles were achieved in this study. Combining LN2 with cyclic N2 and/or CO2 injections can result in flow-conductivity enhancement, induced-cracks growth, and oil–gas interaction development throughout the injection to production stages, which enhance the stimulated volumes leading to oil RF improvement. Compared to LN2-assisted N2 huff-n-puff, better performance of injecting CO2 after LN2 was observed on samples of low permeability, particularly when utilizing injection pressure near CO2-MMP, 20.68 MPa, resulted in RF of 53%, 26% higher than injecting N2 at the end of cycle#3. Injecting LN2 with N2 into samples of high permeability (greater than 0.1 mD) has the potential to recover oil up to 57% due to the presence of the moveable oil that can flow easily from deeper areas to surface, unlike the samples of low permeability (<0.1 mD), where oil RF at the end of cycle#3 was 27%. LN2-assisted N2-CO2 huff-n-puff increases the incremental oil RF on low permeable samples, resolving the issue related to the fact that the incremental RF would start declining sharply in the second cycle and as the number of cycles increases when using only N2 injection. From the results observed in this study, a combination of cryogenic treatment and huff-n-puff techniques would be potentially implemented in shale oil reservoirs, opening the opportunity to improve shale oil RF by enhancing the flow-conductivity and increasing the hydrocarbon mobility.

Analysis of Microstructure and Low Permeability with 3D Digital Rock Modeling

The sandstone microstructure and permeability are important parameters for quantitative evaluation of groundwater/oil/gas resources and prediction of flow rates of water/oil/gas. In this study, we applied seven low-permeability sandstone samples obtained from North China to research the microstructure and permeability based on digital core technology. Rock images were collected by X-ray microcomputed tomography (μCT), and then software (Avizo) was applied to analyze the microstructure and calculate the parameters such as porosity, connected porosity, average equivalent diameter, tortuosity, and shape factor. By introducing the shape factor into the Kozeny–Carman equation, we modified the Kozeny–Carman equation and found that the modified equation is a function of porosity, diameter of particles, tortuosity, and particle shape factor.

Workshop: Best-practice for laboratory testing low-permeable materials

Abstract. The testing of low-permeable materials is challenging. Yet, for the disposal of radioactive waste, it is essential, too. This workshop is aimed at gathering ambitious scientists to discuss and to collaborate on their experiences in the laboratory testing of low-permeable materials. The focus here is on the methods: What method is best for what kind of low-permeable host rock (salt/clay) and for what kind of technical barrier material (bentonite/crushed salt)? How can measurement errors be correctly determined? What are the crucial “bottlenecks” in the device setups? How can high porous but low permeable samples best be pre-saturated? How can coupled flow and cumbersome gas traps in the tests be dealt with? What is the best-practice analysis of permeability from pressure decay recordings? Is there a hope of defining a standardized procedure for low-permeability testing? These points will be reflected in the light of radioactive waste disposal and in the need to find a best-practice solution when it comes to eventual evaluation and comparison of potential underground disposal sites.

A Laboratory Approach to Measure Enhanced Gas Recovery from a Tight Gas Reservoir during Supercritical Carbon Dioxide Injection

Supercritical carbon dioxide injection in tight reservoirs is an efficient and prominent enhanced gas recovery method, as it can be more mobilized in low-permeable reservoirs due to its molecular size. This paper aimed to perform a set of laboratory experiments to evaluate the impacts of permeability and water saturation on enhanced gas recovery, carbon dioxide storage capacity, and carbon dioxide content during supercritical carbon dioxide injection. It is observed that supercritical carbon dioxide provides a higher gas recovery increase after the gas depletion drive mechanism is carried out in low permeable core samples. This corresponds to the feasible mobilization of the supercritical carbon dioxide phase through smaller pores. The maximum gas recovery increase for core samples with 0.1 mD is about 22.5%, while gas recovery increase has lower values with the increase in permeability. It is about 19.8%, 15.3%, 12.1%, and 10.9% for core samples with 0.22, 0.36, 0.54, and 0.78 mD permeability, respectively. Moreover, higher water saturations would be a crucial factor in the gas recovery enhancement, especially in the final pore volume injection, as it can increase the supercritical carbon dioxide dissolving in water, leading to more displacement efficiency. The minimum carbon dioxide storage for 0.1 mD core samples is about 50%, while it is about 38% for tight core samples with the permeability of 0.78 mD. By decreasing water saturation from 0.65 to 0.15, less volume of supercritical carbon dioxide is involved in water, and therefore, carbon dioxide storage capacity increases. This is indicative of a proper gas displacement front in lower water saturation and higher gas recovery factor. The findings of this study can help for a better understanding of the gas production mechanism and crucial parameters that affect gas recovery from tight reservoirs.

Experimental study on the oil production characteristics during the waterflooding of different types of reservoirs in Ordos Basin, NW China

Waterflooding experiments were conducted in micro-models (microscopic scale) and on plunger cores from low permeability, extra-low permeability and ultra-low permeability reservoirs in the Ordos Basin under different displacement pressures using the NMR techniques to find out pore-scale oil occurrence state, oil production characteristics and residual oil distribution during the process of waterflooding and analyze the effect of pore structure and displacement pressure on waterflooding efficiency. Under bound water condition, crude oil mainly occurs in medium and large pores in the low-permeability sample, while small pores and medium pores are the main distribution space of crude oil in extra-low permeability and ultra-low permeability samples. During the waterflooding, crude oil in the medium and large pores of the three types of samples are preferentially produced. With the decrease of permeability of the samples, the waterflooding front sequentially shows uniform displacement, network displacement and finger displacement, and correspondingly the oil recovery factors decrease successively. After waterflooding, the residual oil in low-permeability samples is mainly distributed in medium pores, and appears in membranous and angular dispersed phase; but that in the extra-low and ultra-low permeability samples is mainly distributed in small pores, and appears in continuous phase formed by a bypass flow and dispersed phase. The low-permeability samples have higher and stable oil displacement efficiency, while the oil displacement efficiency of the extra-low permeability and ultra-low permeability samples is lower, but increases to a certain extent with the increase of displacement pressure.

Lab-scale and pore-scale study of low-permeability soil diffusional tortuosity

Diffusion coefficients for Na+ was measured in low-permeability samples (diameter of 3 cm and average length of 7 cm) from the deep disposal site of the Siberian Chemical Combine (SCC) using the end-diffusion technique. The direction of diffusion was perpendicular to the direction of bedding. Special equipment was designed and constructed for the experiment. Two types of concentration observations were used. For non-sorbing Na+, EC sensors and the length distribution of sorbed elements were used. The synthetic solution used in the experiments was a model of the low-activity contaminant of the SCC and consisted of NaNO3 (25 g/L) and nitrate compounds of Cs+, Ni2+, Co2+, and Sr2+ (100 mg/L each). The measured values of the effective diffusion coefficients De for Na+ from 1.92 × 10−11 to 1.70 × 10−10 m2/s. The microstructure was studied with X-ray microtomography for the same cores. Image shooting was performed on undisturbed microsamples with a size of 0.913 mm (7003 vox). Spatial correlation analysis was performed after the binarization of each obtained 3-D structure. This analysis showed that the spatial correlation scale of the indicator variogram is considerably smaller than the microsample length. Then, a numerical simulation of the Laplace equation with binary coefficients for each microsample was performed. The results were analysed in the form of a plot of the tortuosity versus the porosity. Pore-scale simulations show a nonlinear decrease in the tortuosity with decreasing porosity. Exponential values in the range between 1.8 and 2.4 were found by fitting this graph with Archie's model. Anisotropic tortuosity is also detected in the horizontal and vertical directions. The diffusion coefficients of non-sorbing Na+ measured in this study agree with those of the pore-scale diffusion simulation of the microtomography data.

Modeling acidizing of carbonate formations with different reservoir properties

Introduction. The efficiency of matrix acidizing of the bottom-hole formation zone depends on many factors, the chief being the reservoir properties. The research aim is to assess the effect produced by the formation reservoir properties on the result of hydrochloric acid treatment. Experiments simulating carbonate formation acid treatment were carried out. Methods. The experiments were carried out using the UIK-1 core analysis apparatus. Carbonate cores with different porosity and permeability were selected. Some of the experiments modeled permeability reduction as a result of bottom-hole formation zone contamination with drilling mud. Results. The research has shown that during low permeability reservoirs acidizing, permeability increases to a greater extent than during high permeability cores acidizing. In low permeability cores, the acid solution mainly forms new channels, while in high permeability cores the expansion of existing ones mainly occurs. In the present paper, the equivalent surface area of the acid-formed channels was estimated. When acidizing low permeability cores, the equivalent area of the channels is larger than when acidizing high permeability cores. The outcome of acidizing of the core samples with impaired porosity and permeability and contaminated with model drilling mud is comparable to acidizing of low permeability samples not contaminated with drilling mud. Conclusions. Acidizing of low permeability reservoirs leads to a greater increase in permeability. The equivalent area of acid-formed channels is larger than that of high permeability cores treatment. This reveals that the impact of acid on low permeability reservoirs is more effective.

Impact of water saturation on gas permeability in shale: Experimental and modelling

Shale gas is becoming more important in clean energy supply. There is original water content in shale pores under reservoir condition. In addition, the introduction of water-based fracturing fluid during hydraulic fracturing process also changes the shale reservoir water saturation. Water saturation has a profound impact on the gas effective permeability and its anisotropy, thus on shale gas production. Previous experimental studies on gas effective permeability were mostly on dry samples. Due to the great difficulty in gas-water two-phase flow experiment, there are very few experiments to study the impact of shale water saturation on gas permeability. How water content affects gas effective permeability is not well understood. This work proposes an experimental method to investigate the effect of water saturation on stress-dependent gas permeability. Moreover, the experimental method and gas permeability results are compared between this work and literature. An integrated permeability model considering the impact of water saturation is proposed. It is found that the water content has significant impact on gas effective permeability and the impact is more significant for low permeability samples.

IMPACT OF WATER AND CO2 ON THE MECHANICAL PROPERTIES OF LOW PERMEABLE ROCKS

This article features experiments on triaxial compression of low-permeable dolomite samples with different confining pressures (2-20 MPa), different pore fluids (dry air, water, CO2), and different temperatures (25-150 °C). The authors have studied the effect of confining pressure, pore fluid and temperature on the strength properties of the studied samples. The results show an increase in the strength with grwoing confining pressure. When the confining pressure increases from 2 to 20 MPa, the compressive strength increases from 86 to 370 MPa. Temperature has a significant effect on rock strength under low confining pressure conditions. With the increasing confining pressure reaching 15 MPa, increasing temperature has little effect on the strength of dolomite samples. Under an effective confining pressure of 5 MPa, the temperature weakening occurs on the dolomite specimens when the temperature exceeds 90 °C. During compression, liquid diffusion occurs in the specimens. Higher water viscosity can cause a temporary decrease in effective confining pressure, which can increase the strength of the rock. More prominent fractures are observed in the samples, and more fluid is injected under CO2 injection conditions, which may be useful for increasing the permeability of the geothermal reservoir. Two groups of experiments have been performed on the samples in this study: the first group of experiments investigated the effect of confining pressure on the fracture stress of core samples, without pore fluid injection; the second group of experiments investigated the effect of water or CO2 and temperature on the mechanical properties of core samples.

Petrophysical characterization of low-permeable carbonaceous rocks: Comparison of different experimental methods

Pore structure and gas transport properties of fourteen samples from the Jurassic Sargelu and the Cretaceous Garau formations in Lurestan province, southwest Iran, were studied under the aspect of shale gas exploration and production.Porosity was determined by helium pycnometry and water saturation (Archimedes principle). Low-pressure adsorption of N2 was used to determine total pore volumes, specific surface areas and microporosity. High-pressure mercury intrusion porosimetry (MIP) was applied to assess pore-size distributions. Permeability measurements were performed with helium and methane at confining pressures of 40 to 10 MPa using steady state and non-steady state methods.Permeability and porosity values determined by the different methods are in a good agreement. For low-permeable samples (less than 1 microdarcy ~ 10−18 m2) the “constant downstream pressure” technique is the most efficient method for slip flow evaluation (Klinkenberg plot), yielding apparent permeability coefficients over a wide range of reciprocal mean pressures (1/pmean) in one single run.A positive correlation was found between TOC content, porosity and permeability coefficients. Samples displaying clear signs of recrystallization tend to exhibit higher permeability. None of the parameters determined in this study, however, showed a correlation with mineralogy.The relationship between Klinkenberg-corrected permeability coefficients and confining pressure could be expressed by an exponential decay function. Stress sensitivity was typically higher for low-permeable samples. Samples containing highly recrystallized carbonates exhibited lower stress sensitivity, indicating an increase in rigidity due to recrystallization.No correlation was found between methane/helium permeability ratios, sorption capacity, and TOC contents. Thus, gas transport properties of this sample set were not affected by sorption and/or swelling of organic matter.

Interplay between Rock Permeability and the Performance of Huff-n-Puff CO2 Injection.

The CO2 huff-n-puff experiments are often conducted on a rock sample with a given permeability. However, there is a need for understanding the production performance of CO2 huff-n-puff over a range of rock permeability values. In this study, CO2 huff-n-puff corefloods were conducted by using 30 cm long artificial cores over a permeability range between 0.7 and 240 mD. After that, the cores and produced oil were analyzed by NMT tests and gas chromatography tests. The effects of rock permeability on primary parameters, such as ultimate oil recovery, gas and oil ratio (GOR), pressures, residual oil distribution, and produced oil composition, were studied in detail. The experimental results indicate that the overall CO2 huff-n-puff efficiency increases with permeability, while the production dynamics also changes with permeability. The oil production is greater and realized faster in high permeability core samples than low-permeability rocks; hence, maintaining the same production efficiency for low-permeability samples needs more production cycles and a longer production time. Fortunately, the GOR of CO2 huff-n-puff in low-permeability samples is lower, which is favorable in long-term production. In contrast, a larger produced GOR is realized in high-permeability core samples, especially beyond the optimal cycle. Moreover, although the CO2 front occurs at a shorter distance from the inlet as rock permeability decreases, CO2 huff-n-puff can simultaneously produce oil from different pore sizes of different permeability core samples. The permeability of core samples also has a significant influence on the composition of the produced oil. The CO2 extraction capability is stronger in samples with a lower permeability.

Critical Diagenetic Features Controlling Intergranular Flow Paths and Matrix Permeability in the Codell Sandstone, Northeastern Colorado

The Codell Sandstone is a hydrocarbon-bearing, tight sand (permeability &lt;0.1 mD) that is an active target for unconventional hydrocarbon production in the Denver-Julesburg Basin. In northeastern Colorado, the intergranular microporous drainage network within this clay-rich sandstone is poorly understood, with a strong diagenetic control suggested by the lack of correlation between permeability and depositional facies. Core samples from the Wattenberg Field and Redtail areas in Weld County were used to identify which diagenetic processes were most important in developing a connected pore network. Thirteen diagenetic features were defined using thin-section petrography and electron microprobe mineralogical phase mapping, and skeletonized flow paths were delineated by epifluorescence imaging. Quartz overgrowths, mechanical compaction, and clay cements (illite, chlorite, and kaolinite) are better developed in the laminated facies than the burrowed facies. Authigenic calcite and pyrite, and dissolution of framework grains are equally developed in both types of facies. Cumulative 2D flow-path lengths positively co-vary with permeability, indicating that the skeletonized paths capture the features that control permeability. The longest flow paths in high permeability (≥0.09 mD) samples follow micropores created along the periphery of framework grains where the discontinuous quartz overgrowths abut clays. Micropores within intergranular clay masses (detrital, pore-filling cements, and authigenic replacements) associate with shorter flow paths that dominate in low permeability (≤ 0.01 mD) samples and feed the longer paths in high permeability samples. While compaction and all types of cements had a negative impact on the original pore network, the development of long contacts between quartz overgrowths and mechanically juxtaposed grains eventually became beneficial to the drainage system. The increased surface area along those contacts increased the continuity of the flow paths developed along grain surfaces. All observations indicate that the minute quartz overgrowths, and the high authigenic rugosity they created along grain boundaries, were a key diagenetic event in creating the most efficient drainage networks that now facilitate the movement of hydrocarbons at the core-plug scale.