Mercury Injection Capillary Pressure Research Articles

Pore size distribution and reservoir characterization: evaluation for the Eocene beach-bar sequence, Dongying Depression, China

Pore size distribution and associated heterogeneities of thinly bedded beach-bar sandstone reservoir from upper fourth member of Eocene Shahejie Formation (Es4s) are characterized with the help of mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) transversal relaxation time (T2) data. Permeability and porosity are two represented important characteristics of rocks that control the movement and storage of fluids. The aim of this paper is to establish relationships between pore throat sizes and reservoir quality. The results derived from thin-section petrography, scanning electron microscopy (SEM), MICP, NMR T2 relaxation time, and 3D micro-CT (μ-CT) are compared to characterize pore space dimensions and types comprehensively. Average pore throat size from MICP ranges between 0.47 μm and 2.83 μm while maximum pore throat size ranges between 2.48 μm and 7.36 μm. The combination of pore size distribution obtained from MICP and NMR seems appropriate to cover the range of pore size from beach-bar sand and overcome the individual method limits. Afterwards, digital 3D μ-CT tomographic images are used to characterize and visualize pore space and pore network model to compare with the experimental data. MICP and NMR experiment showed generally bimodal (meso and micro) pore size distribution. Usually mesopore corresponding to intergranular pores is dominant, while heavily cemented sandstones show large amounts of intercrystalline micropores. Complex and heterogeneous beach-bar sandstone reservoir requires comprehensive study program to evaluate the reservoir.

Laboratory treatment of HPAM polymers for injection in low permeability carbonate reservoirs

Polymeric solutions are injected into petroleum reservoirs to improve sweep efficiency of enhanced oil recovery processes. Viscous polymeric solutions cannot be injected into non-fractured low permeability carbonates (k < 50 mD) if a significant fraction of pore throats is smaller than the polymer molecules. Mechanical shear degradation and aggressive microfiltration can be applied as tools to modify the molecular weight distribution (or hydrodynamic radius) of polymers. High speed mechanical shearing in a laboratory blender showed significant reduction in viscosity and polydispersity for the polymer stock solutions with improvement in filterability and transport in low permeability porous media. Aggressive filtration through small sized filter papers proved to be a good technique for refinement of molecular weight distribution and removing larger molecules for successful injection in low permeability carbonates. Dynamic light scattering (DLS) method was used to measure the size distribution of shear degraded polymer solutions at low concentrations. The optimum shear degradation required for a high MW polymer to be successfully injected into a low permeability carbonate reservoir was decided by comparing the polymer size distribution with the pore throat diameter distribution obtained from mercury injection capillary pressure (MICP) for the rock. This novel technique was successfully applied for injection of viscous polymer solutions in carbonates with permeability less than 20 mD. The pore throat distribution of a porous medium is more important than the permeability (or average hydraulic radius) for the transport of polymers in porous media.

Pore size distribution, their geometry and connectivity in deeply buried Paleogene Es1 sandstone reservoir, Nanpu Sag, East China

The study of pore characteristics is of great importance in reservoir evaluation, especially in deeply buried sandstone. It controls the storage mechanism and reservoir fluid properties of the permeable horizons. The first member of Eocene Shahejie Formation (Es1) sandstone is classified as feldspathic litharenite and lithic arkose. The present research investigates the pore characteristics and reservoir features of the deeply buried sandstone reservoir of Es1 member of Shahejie Formation. The techniques including thin-section petrography, mercury injection capillary pressure (MICP), scanning electron microscopy and laser scanning confocal microscope images were used to demarcate the pores including primary intergranular pores and secondary intergranular, intragranular, dissolution and fracture pores. Mercury injection test and routine core analysis were led to demarcate the pore network characteristics of the studied reservoir. Pore size and pore throat size distribution are acquired from mercury injection test. Porosity values range from 0.5% to 30%, and permeability ranges 0.006–7000 mD. Pore radii of coarse-grained sandstone and fine-grained sandstone range from 0.2 to > 4 µm and 1 nm to 1.60 µm, respectively, by MICP analysis. The mineral composition also plays an important role in protecting the pores with pressure from failure. Fractured sandstone and coarse-grained sandstone consist of large and interconnected pores that enhance the reservoir porosity and permeability, whereas fine-grained sandstone and siltstone consist of numerous pores but not well interconnected, and so they consist of high porosity with low permeability.

Rock properties from micro-CT images: Digital rock transforms for resolution, pore volume, and field of view

Digital Rock Physics is a promising approach for achieving more, cheaper, and faster rock property characterization of digital images of rock samples. To successfully deliver on this potential, we must correctly interpret the digitally derived properties in the context of the limitations imposed by imaging constraints. To this end, we show that a combination of limited image resolution, a biased segmentation of images with coarse resolution, and a finite field of view of images, generated by the present micro-Computed Tomography (micro-CT) technology, leads to systematic underestimation of porosity (down to a factor of 0.5) and overestimation of permeability (up to a factor of 10) calculated using the Digital Rock Physics (DRP). We demonstrate these imaging limitations can be overcome by identifying good measures of image resolution and representative elementary volume and applying appropriate transforms. These transforms expand the operating envelop of DRP. Transforms for finite image resolution and limited field of view can be estimated directly from the micro-CT images. However, implementation of transforms related to errors in image segmentation require either a higher resolution image (e.g., nano-computed tomography, scanning electron microscopy) or laboratory measured constraints (Mercury injection capillary pressure, NMR porosity). Additionally, we suggest how insights from these transforms can be used to define operating envelopes and optimize imaging resolution and field of view to achieve more reliable results from digital rock characterization and simulations.

Nuclear magnetic resonance characterization of porosity-preserving microcrystalline quartz coatings in Fontainebleau sandstones

The almost-pure quartz–cemented Fontainebleau Formation (Paris Basin, France) sandstones are known to preserve their porosity because of microcrystalline quartz coatings. Here, we use nuclear magnetic resonance (NMR) techniques, petrography, scanning electron microscopy, porosity and permeability measurements, hysteresis, and mercury injection capillary pressure curves to identify and analyze their porosity structure. Nuclear magnetic resonance experiments include transverse relaxation time (T2) distributions and T2-filtered T2–T2 exchange (T2F-TREx), a technique that provides estimates on the diffusion coupling by comparing the evolution of families of pores in T2 distributions at different exchange times. Samples were divided according to their texture, composition, and abundance of microcrystalline quartz crystals, comprising group 1 samples with very low amounts of coatings and group 2 samples with entire grains coated by microquartz. Both groups show three (or four) peaks in NMR 2-MHz T2 distribution at approximately 1 (peak A), 10−1 (peak B), and 10−2 s (peak C); group 2 samples present a slight shift to shorter T2 times in comparison with other samples. The longest T2 peak A is because of intergranular macropores, whereas the shortest peak C is because of the microporosity associated with the microcrystalline quartz coating at the surface of the pores. Peak B is also because of microporosity associated with microcrystalline quartz, but with a different surface/volume ratio being likely related to flat-shaped pores within the microcrystalline coating. The T2F-TREx indicates the proton exchange is higher between macropores and the pore surface micropores (peak C) than between macropores and the internal flat-shaped micropores; no exchange between the two sets of micropores can be observed. Our results show the potential of NMR techniques in characterizing the microporosity in Fontainebleau sandstones, which is key for the mechanism of porosity preservation in these rocks.

Sensitive parameters of NMR T2 spectrum and their application to pore structure characterization and evaluation in logging profile: A case study from Chang 7 in the Yanchang Formation, Heshui area, Ordos Basin, NW China

Abstract The evaluation of the pore structure of tight sandstone reservoirs has a significant influence on the effective exploration and development of tight sandstone oil. Laboratory measurements including scanning electron microscopy (SEM), mercury-injection capillary pressure (MICP), gas adsorption, nuclear magnetic resonance (NMR), and Nano-CT can provide detailed pore structure data. However, only NMR results can be used to evaluate the pore structure in a logging profile due to NMR logging. In this study, the relationships between NMR T2 distribution, pore structure, and pore size of tight sandstone in Chang 7 of the Yanchang Formation, in the Heshui area of the Ordos Basin, are analyzed based on NMR principles. The characteristics of the NMR T2 distribution of different rock samples are analyzed; the sensitive parameters of the NMR T2 spectrum are proposed. These parameters are then used to classify pore structure types in tight sandstone reservoirs and divide the active layers in the logging profile of the study area. The results indicate that different pore size structures have different distributions, and that the NMR T2 spectrum can highlight the difference in the pore structure type and pore size distribution using sensitive parameters such as T2P2 (the value of T2 corresponding to the last peak of the bimodal NMR T2 spectrum) and TDM (the mean value of T2 relaxation time obtained by weighted average method). As the pore structure of the rock samples in the study area worsened, their porosity and permeability worsened, T2P2 and TDM decreased, and the displacement pressure and NMR irreducible water saturation increased. The results of classifying the pore structure types obtained in the logging profile are helpful in evaluating the effectiveness of the reservoir and in the broad application of NMR logging in terms of understanding pore structure.

Nuclear magnetic resonance surface relaxivity and its advanced application in calculating pore size distributions

Abstract Both laboratory and downhole nuclear magnetic resonance (NMR) measurements are commonly used to calculate the pore size distribution (PSD) that is important in determining the reservoir storage capacity and evaluating producibility, etc. The surface relaxivity is a key parameter to calculate the PSD using NMR transversal relaxation time (T2) distributions. Accurate surface relaxivity value would result in a reasonable PSD. In order to comprehensively study surface relaxivity, the conventional sandstone, tight sandstone, and shale samples are selected to perform experiments including porosity, permeability, NMR, mercury injection capillary pressure (MICP) and low temperature nitrogen adsorption (LTNA), etc. Three approaches, including LTNA, MICP, and Kozeny's equation, are used to determine the surface relaxivity. We find that for all samples, the surface relaxivity determined with Kozeny's equation is greater than that using LTNA and MICP data, indicating that surface relaxivity of smaller pores is less than that of bigger pores. It is also observed that the surface relaxivity of conventional sandstone is greater than that of tight sandstone and shales. The surface relaxivity of sandstone and shale samples are both affected by clay content. For shale samples, the surface relaxivity ranges from 3.41 μm/s to 9.79 μm/s and is influenced by organic matter contents as well. An equation for predicting surface relaxivity of shale is established. Finally, we propose an advanced method for calculating reasonable PSDs of sandstone and shale formation by the combination of two surface relaxivities, which could be applied to laboratory and field wells.

Investigation of factors influencing geological heterogeneity in tight gas carbonates, Permian reservoir of the Persian Gulf

Understanding the spatial distribution of petrophysical properties in carbonate reservoirs is complicated due to their heterogeneity and sensitivity to diagenesis along with important facies variations. The reservoir evaluation in tight carbonates is even more complicated. The Permian Dalan Formation in the central part of Persian Gulf is generally considered as conventional carbonate reservoir. However, in this study, a part of K3 unit of this formation is introduced as a tight carbonate reservoir. To identify the factors influencing the quality of this unit, the sedimentary facies, depositional environments, diagenetic processes, and pore-type distribution were studied in details on 402 thin sections. Porosity and permeability of K3 are mainly controlled by dolomitization, dissolution, compaction, and cementation. MICP-based (mercury injection capillary pressure) methods, FZI*(FZI-star), and rock fabric numbers were considered to recognize the factors controlling heterogeneity of this unit. The MICP-based methods of Winland, Pittman, and Rezaee were combined with 3 porosity cutoffs to detect the heterogeneities of tight carbonates. None of these methods provided a high degree of correlation between porosity and permeability of the samples. The results of rock fabric number showed that samples with similar reservoir quality are the product of different diagenetic processes. Results obtained in this study demonstrate that the FZI*(FZI-star) and rock fabric number classifications are the most suitable methods for differentiating the tight zone and non-reservoir/reservoir parts in carbonates of K3 unit.

Complementary neutron scattering, mercury intrusion and SEM imaging approaches to micro- and nano-pore structure characterization of tight rocks: A case study of the Bakken shale

Small angle neutron scattering (SANS) and ultra-small angle neutron scattering (USANS) techniques have been increasingly utilized to study tight rocks (e.g., mudrocks), due to their capabilities of detecting total pore spaces (both body and throat) across the nm-μm spectrum. Mercury injection capillary pressure (MICP) is a widely employed technique in the oil and gas industry, used to obtain a variety of petrophysical properties of porous rocks. In this study, we selected six samples from the three (i.e., lower, middle, and upper) members of the Bakken Formation (Late Devonian to Early Mississippian) in the Williston Basin, North Dakota. We utilized the complementary techniques of (U)SANS and MICP to characterize and differentiate their pore systems over a broad measurable range of pore/throat sizes from 1.25 nm to 50 μm. Detailed processing of (U)SANS scattering data is illustrated to show how the total porosity and pore size distribution are obtained and compared against MICP analyses. The results show that the lower/upper Bakken samples and the middle Bakken samples have distinct mineral compositions and organic matter contents, which could be important factors affecting their pore structure. Assisted with the field emission-scanning electron microscopy (FE-SEM) technique, it was found that organic matter-hosted pores contribute a significant portion of total porosity in the lower/upper Bakken shales, while the middle Bakken samples are mostly composed of mineral pores. Additionally, the porosities measured by the (U)SANS and MICP techniques are related to sample sizes employed for each approach, due to a limited pore accessibility of mudrocks; a larger sample size will possess a higher proportion of isolated pores. In general, the results for the Bakken samples in this study indicate that the combination of (U)SANS, MICP, and FE-SEM approaches gives a more complete picture of the pore structure of tight rocks.

Description of chalk microporosity via automated mathematical morphology on scanning electron microphotographs

The spatial geometry of microporosity influences fluid flow through chalk reservoirs and aquifers, and, hence, numerous geological processes. Analysing porosity is thus often critical in geological studies. Techniques such as mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR) and X-ray computed tomography (CT) are expensive, and hence often inapplicable to many geological studies, which often necessitate the analysis of large numbers (hundreds) of samples. However, scanning electron microscopes (SEM) have become widely available, and SEM imagery analysis, therefore, is cheaper and faster. However, extracting meaningful porosity descriptors from SEM images can be difficult, in part because of the difficulty in digitally separating pores in laterally continuous pore networks. Moreover, mathematical morphology can be automated to collect porosity parameters from hundreds of images in a short time frame. The technique also quantifies the shape complexity of porosity. Considering the influence of pore geometry on fluid flow, the capacity of image analysis to deconstruct the pore network by pore shapes is crucial when building flow models. This study concludes that mathematical morphology constitutes an alternative to other techniques in geological studies of microporosity. Lithologies dominated by micro- and nanoporosity, such as shales and tight sandstones, could also benefit from this technique.

Integrated geological and petrophysical characterization of oligocene deep marine unconventional poor to tight sandstone gas reservoir

The present study aims to evaluate, discriminate and delineate the geological and petrophysical situation of Oligocene reservoir wells at Salamat-1 and Atoll-1 in North Damietta offshore concession in the Mediterranean Sea. It deals with a combined interpretation of the core analysis (density, porosity, permeability and mercury injection capillary pressure ‘MICP’) and petrography data (thin sections, scanning electron microscope and X-ray diffraction) as well as well log (gamma ray, density, neutron, micro spherical logs ‘MSFL’, shallow and deep resistivity, and Modular Formation Dynamic Tester logs) and the subsurface geologic data, as well as some available seismic sections to clarify the geological and the petrophysical characterization of the Oligocene unconventional tight sandstone gas reservoir, Salamat structure, North Damietta offshore, Mediterranean Sea, Egypt. Petrophysically, the studied sandstone core samples can be summed up into two reservoir rock types (RRT), where poor reservoir quality is assigned to one group while the other is characterized by tight reservoir properties. These two RRTs are discriminated into four microfacies, two arenite groups and two wacke groups. Filling the pore spaces with detrital clays are the most important reservoir quality-reducing factors. The seismic data indicates that the studied area is composed of Rupelian-Chattian multi-channel system located off shore with many sand channels distributed in the area. The Lower and Upper Chattian sand channels comprise the most important reservoir bodies in Atoll-1 well to the northeast of the study are gas-bearing bodies, whereas the Rupelian sand channels to the northwest at Salamat-1 well are the most important gas-bearing channels. Integration between the available core and well log data indicated that the best storage and flow capacity are assigned to the other water-bearing sand channels rather the gas-bearing channels in both Salamat-1 and Atoll-1 wells. • The Rupelian-Chattian multi-channel sandstones are the target of this study. • Delineate the geological and petrophysical situation of Oligocene clastic reservoirs. • Petrophysically, two reservoir rock types can be assigned in the studied sequence. • Petrographically, the studied samples are discriminated into four microfacies. • Filling the pore spaces with detrital clays is the main reservoir quality-reducing factor.

Effect of addition of surface water treatment sludge to biomass in biochar porosity

Samples of pruning sawdust (PS) and water treatment plant (WTP) sludge residue were collected and mixed in proportions of 10 to 80% of WTP sludge in PS, submitted to torrefaction at 260 °C, and the resulting biochar samples were submitted to TG/DTG analysis to assess their decomposition, thermal stability, and immediate analysis. Also, the nitrogen adsorption–desorption isotherm, mercury-injection capillary pressure (MICP), ultimate analysis, SEM, EDS, and FTIR were employed. The biochars of blend with 20% of sludge (BB20) and PS without sludge (BBM) were the ones that presented the best stability test in an aqueous medium. The biochar BB20 presented thermal stability (190 °C), moisture (5.7%), volatiles (48.6%), fixed carbon (35.9%), ash (9.8%), BET surface area ($$0.7942\,{\hbox {m}}^{2}{\hbox {g}}^{-1}$$), mean pore diameter ($$389.13\,{\AA}$$), adsorption–desorption isotherm characteristic of the mesoporous material, highest MICP total pore volume, porosity (76.7%), total pore area ($$62.859\,{\hbox {m}}^{2}{\hbox {g}}^{-1}$$), mean pore diameter ($$0.1322\,\upmu\,{\hbox {m}}$$) , the predominance of macropores. The biochar BBM showed BET surface area ($$1.3366\,{\hbox {m}}^{2}\,{\hbox {g}}^{-1}$$), mean pore diameter ($$169.97\,{\AA}$$), adsorption–desorption isotherm characteristic of mesoporous material, better second one MICP total pore volume, porosity (64.4%), total pore area ($$76.520\,{\hbox {m}}^{2}\,{\hbox {g}}$$), mean pore diameter ($$0.0786\,\upmu \hbox {m}$$) also, macroporosity. According to the results presented, the biochar BB20 itself to several uses as substitution of anthracite coal in water and filtration systems plant for the wastewater treatment due to macroporosity and as a viable solution to the reuse of these two residues.

Petrophysical static rock typing for carbonate reservoirs based on mercury injection capillary pressure curves using principal component analysis

Rock typing lay the profound basis of rational and efficient development of oil and gas reservoirs. In carbonate reservoirs, however, the identification of petrophysical static rock type (PSRT) has always been a great challenge to reservoir engineers and geologists due to its strong heterogeneity arising from the diagenetic process. The objective of this study was to propose a new method for petrophysical static rock typing in carbonate reservoirs. First, the evaluation equation of mercury injection capillary pressure (MICP) curve was established based on parameters analysis, and parameters weight was assigned by using the entropy method. Then, by analyzing and selecting the key influential parameters regarding the PSRTs in carbonate reservoirs, the novel rock typing model was established by principal component analysis (PCA) and ordinary least square (OLS) method. Finally, a realistic field case in Mishrif formation was presented through comparing the results from the proposed model with that of the existing methods, such as Winland plot (r35), flow zone indicator (FZI), FZI-star (FZI*) as well as bulk volume water method (BVW). The results indicated that the PSRTs identified by the new proposed model were superior to the others. What is reflected in the proposed model is that this approach can directly identify the PSRTs of the target formation. In contrast, neither the method of FZI nor the r35 can independently identify the PSRTs of carbonate reservoirs, they have to work jointly to determine the PSRTs.

An experimental investigation into the effect of pore size distribution on the acid-rock reaction in carbonate acidizing

This study presents the correlation analysis between pore size distribution and diffusion coefficient based on the experimental results to evaluate the effect of pore size distribution on the acid-rock reaction in carbonate acidizing. The mercury injection capillary pressure (MICP) was used to analyze the pore size distribution of four limestone samples. Also, the acid-rock reaction experiments were conducted to measure diffusion coefficients using rotating disk apparatus (RDA). In the experimental results, micropore dominated rock samples have lower dissolution rate and diffusion coefficient than macropore dominated rock samples. It is obviously revealed that the dissolution rate and diffusion coefficient for limestone samples with similar mineral compositions are quite different due to various pore size distribution. In the result of correlation analysis, it is revealed that neither porosity nor permeability exhibits a strong correlation with diffusion coefficient compared with pore size distribution. Therefore, it can imply that the petro-physical properties such as porosity and permeability have a lower relevance to the acid-rock reaction kinetics than pore size distribution. To investigate the effect of pore size distribution on matrix acidizing, optimum injection rates were derived by the experimental results. As a result, the optimum injection rates increase with the mean and median pore size, and the micropore dominated rock samples show lower optimum injection rate than the macropore dominated rock samples. Although the pore size distribution shows a strong correlations with matrix acidizing, the optimum injection rate has been estimated without ample considerations of pore size distribution. Therefore, the effect of pore size distribution on diffusion coefficient should be considered to design the optimum injection conditions in carbonate acidizing job.

A new correction method for mercury injection capillary pressure (MICP) to characterize the pore structure of shale

The economic and accurate measurement of micron or submicron size pores in shale is still a challenge. The mercury injection capillary pressure (MICP) measurement of shale particles is an effective method to evaluate the macropore structure, but it is questionable without proper data interpretation. In this study, the fractal theory was applied to identify the four stages of MICP measurement: Stage A is controlled by the interparticle voids in the particle assemblage; Stage B can reflect mercury intrusion into the pores of the shale; and Stage C and D indicate the shale matrix compression and pore structure change induced by high pressure, respectively. Based on the consistent fractal dimension derived from Stage A, the conformance volume induced by interparticle voids at each pressure step in Stage B was quantitatively simulated using the linear fitting method. The correction results show that simultaneous mercury filling of interparticle voids has an important impact on the pore volume in the pore size range larger than 1 μm. To cover the complete pore size range, the MICP data in Stage C and D were substituted by gas adsorption data.The new correction method for MICP data was verified by the good match between the MICP-gas adsorption combined porosity and the helium porosity of the same sample and by the good agreement between the pore size distribution (PSD) curves from the MICP and N2 adsorption measurements in their overlapped pore size range. Therefore, the MICP and gas adsorption methods can be used in conjunction to characterize the pore structure of shale in the complete pore size range. The application of this method is particularly good for the silty samples of lacustrine shale in the study area compared with the clayey samples. To further improve the convergence of different fluid injection methods, more efforts are needed to determine the optimum particle size class and optimum data interpretation model for different shale lithofacies.

Carbonate rocks resistivity determination using dual and triple porosity conductivity models

Abstract The rocks may be classified as Archie rocks or Non-Archie rocks, depending on the link between pore structure and resistivity of the rock. For carbonate rocks, keeping this factor in view, the applicability of Archie's law tends to be unreasonable and employing Archie's equation will ultimately lead to inaccurate estimates of the water saturation. Numerous investigators have reported models that forms a link between laboratory results and field well logs to determine water saturation in intricate pore systems. In case of complex systems, Archie's law fails to correctly define the resistivity-index curves. In addition, it is imperative to carry out investigations at lower saturation values in order to elaborate the non-Archie characteristics. This brings the dual and triple porosity conductivity models into the equation. As these models are essential in defining the considerable changes of the resistivity-index curves, both qualitatively and quantitatively. The linkage between the two models is depicted electrically in series or in parallel. Moreover, it is possible to have a combination of the two configurations. As a result, the experimental results can be modeled accurately using least parameters. This work presents two models to determine water saturation in carbonate rocks, containing dual and triple porosity systems. This study also investigates the impact of different influential parameters such as saturation exponents, conductivity ratios, and pore volume fraction of each network systems, on the new models. Finally, the effect of each parameter is individually studied and the sensitivity analysis on the RI curves is produced. A new approach to apply these models is also explained which requires the use of NMR log, mercury injection capillary pressure (MICP) measurement, and simple plotting techniques to determine the water saturation. The proposed new models help petrophysicists to estimate water saturation in Non-Archie rocks, containing double and triple porosity network systems.

Mineralogic and Diagenetic Controls on Reservoir Quality of Paleozoic Sandstones, Gebel El-Zeit, North Eastern Desert, Egypt

Studying the mineral composition and petrophysical properties of the Cambro–Ordovician sequence in Gebel El-Zeit indicates that it can be discriminated into four rock types, namely quartz arenite (RRT1 of the Cambrian Araba Formation, 35 m; RRT2 of the Ordovician Naqus Formation, 320 m), quartz wacke (RRT3) and mudstone (RRT4) of the Naqus Formation. Diagenesis played a major role in reducing or enhancing the studied microfacies. Cementation by silica, compaction and authigenic clay minerals are the main porosity-reducing factors, whereas dissolution and leaching out as well as fracturing are the most important porosity-enhancing factors. For the present study, reservoir quality was determined using reservoir quality index (RQI), flow zone indicator (FZI) and reservoir potentiality index (RPI) based on helium porosity and permeability values, in addition to the mercury injection capillary pressure (MICP) tests. The best reservoir quality was assigned to the quartz arenite microfacies, whereas the least quality was assigned to RRT4. Reservoir quality is mostly controlled by permeability, which in turn is controlled by the helium porosity and the pore radius of the studied samples (r35 of Winland and r10 of Schowalter). The Araba Formation at the bottom of the sequence is characterized by the best hydraulic flow units (best RQI, FZI, RPI and MICP, rank II). In addition, the middle and top parts of the Naqus Formation have good to very good reservoir quality (rank III).

Imbibition Capillary Pressure and Relative Permeability of Mixed-Wet Microporous Rock: New Insights from History Matching

MC was supported by the University of Aberdeen College of Physical Sciences studentship. The authors gratefully acknowledge CYDAREX for providing an evaluation license for their software CYDARTM , Koon-Yang Lee for the n-decane/brine static contact angle measurements on calcite (Supplementary Material S3), and Steffen Berg for his insightful comments and suggestions as a reviewer for conference paper Christensen and Tanino 2018 on which this paper builds. Finally, the authors thank the three anonymous reviewers for their detailed comments. All data used in this study are available from the corresponding author on reasonable request. In addition, the centrifuge data generated during this study are included as a Excel spreadsheet in the supplementary materials for this published article. One set of mercury injection capillary pressure measurements by Tanino and Blunt (2012) analysed in Text S2 are available in the Mendeley data repository, https://data.mendeley.com/datasets/9f4898jfr9/1.

Integrated pore-scale characterization of mercury injection/imbibition and isothermal adsorption/desorption experiments using dendroidal model for shales

Distinct from conventional reservoirs, shale formations have limited pore connectivity and unique pore spatial-distributions. Consequently, theoretical pore-network models developed for conventional formations are not representative of the pore topology within unconventional rocks. This paper presents a theoretical pore-network model, dendroidal model, based on the analysis of reconstructed pore-scale model extracted from Scanning Electron Microscope images. Dendroidal model is a semi-acyclic model, which characterizes the poor connectivity of void space without sacrificing the interaction between main flow paths. Dendroidal model infers pore-body distribution based on the hysteresis effect of isothermal adsorption/desorption measurements and characterizes pore-throat distribution using mercury injection capillary pressure data. The use of dual-compressibility model in pore-network model construction eliminates the effect of compressibility of both void space and matrix. Total organic carbon (TOC) content and minerology determine the composition of pore bodies and pore throats. The difference in mercury intrusion and extraction caused by trapping hysteresis and contact-angle hysteresis affects the stochastically distributed parameters, including pore-throat length, pore-throat cross-sectional morphology, coordination number and pore-body spatial distribution. We used shale core samples from Marcellus and Wolfcamp formations to validate the dendroidal models by calculating the absolute permeability without slippage effect. This newly developed pore-network model integrates aforementioned seven distinct types of experimental data to capture the realistic pore structures within shales.

Organic nanopore structure and fractal characteristics of Wufeng and lower member of Longmaxi shales in southeastern Sichuan, China

Abstract Organic nanopores in shale gas reservoirs are the main storage space for free gas and adsorbed gas and directly affect the occurrence mode and movement of shale gas. In this study, field emission-scanning electron microscopy (FE-SEM), low-pressure gas (N2 and CO2) adsorption and mercury injection capillary pressure (MICP) analyses were performed and interpreted with statistical and fractal analyses to investigate the organic pore structure in the Upper Ordovician Wufeng shale (O3w) and the Lower Silurian lower member of Longmaxi shale (S1l). It was found that organic pores in 15 samples from 8 layers of the Wufeng-Longmaxi shale section are usually developed in discrete organic matter particles, organic matter associated with clay minerals and organic matter associated with pyrite framboids. The size, shape and quantity of organic pores vary greatly. The organic pores in Wufeng Formation (layer 1) are densely developed in organic matter particles with relatively small sizes and irregular shapes. The organic pores in the lower part of the lower member of Longmaxi Formation (layers 3, 4 and 5) are less developed and have relatively larger pore sizes with an elliptical shape. In contrast, the organic pores in the upper part of the lower member of Longmaxi Formation (layers 6, 7, 8 and 9) are the least developed, with elliptical shapes and pore sizes in between the two cases above. A higher value of fractal dimension refers a more complex form and this value of whole organic pores with full range of sizes (Dwop) is the largest and followed by organic macropores (Dop>50), organic pores with pore sizes between 4 nm and 50 nm (Dop4-50), and organic pores with pore sizes less than 4 nm (Dop