Mercury Injection Capillary Pressure Analyses Research Articles

Permeability evaluation based on Nuclear Magnetic Resonance analysis for gas hydrate reservoir

Permeability (or hydraulic conductivity) is one of the most important parameters for analyzing hydraulic behavior of underground. For example, in the geotechnical engineering, permeability is necessary to calculate water inflow and draw down of water level during excavation, to predict the deformation time due to the consolidation, and to evaluate the barrier of the ground for radioactive waste disposal. In the petroleum industry, permeability is considered an essential parameter which is directly linked to the productivity of oil and natural gas. Therefore, predicting permeability using wireline logging or logging while drilling (LWD) is required during the assessment of the reservoir. Nuclear Magnetic Resonance (NMR) logging is performed at this point. Low-field NMR measurements are sensitive to the hydrogen proton, 1H, in liquid water but not to the 1 H bond in solid form, making it possible to obtain the bulk water volume. In addition, the hydrogen proton NMR- T2 (transverse or spin-spin) relaxation time distribution is used to infer pore-size information and to estimate permeability [1, 2]. The major methods used for estimating permeability, k, are the Schlumberger Doll Research (SDR) model and Timur-Coates (TC) model [3, 4]:
 Where fNMR is the NMR-estimated (effective) porosity. SDR model uses the averaged value of the T2 distribution plotted on log-scale of time and matches it to the experimental reference permeability with the fitting parameter a [mD/(ms)2]. The TC model seeks to differentiate between the fraction of free (mobile) fluid volume (FFV) and bound fluid volume (BFV) and estimates permeability with FFV/BFV ratio and the material constant c [m2/s2]. The permeability in the research and development of methane hydrate, which is expected to be a next-generation resource, has been estimated using above methods. Methane hydrate is an ice-like solid crystalline structure of water and methane molecules. Because hydrate is solid, NMR is not sensitive, the initial (effective) permeability can be estimated by NMR analyzer. On the other hand, A strong disconnect (up to 2 orders of magnitude) between NMR-based estimates of permeability with those determined from a laboratory study of pressure cores from the same reservoir has further cast uncertainty in the application of borehole NMR data in hydrate evaluation [5, 6]. Recently, authors provided comparisons between NMR-derived values and direct fluid flow estimates of permeability in naturally occurring hydrate-bearing sediment [7, 8]. On the basis of the NMR measurement for hydrate-bearing pressure core sediments, which were recovered from the Gulf of Mexico and Alaska North Slope, the following new hydraulic radius model was proposed [7].
 This equation estimates the specific surface based on the NMR signal and has been shown to successfully estimate the initial permeability of a hydrate reservoir by expressing a hydraulic radius model based on Kozeny's equation [9]. However, the proposed equation is not universal and has been found to overestimate for clayey and silty hydrate free sediment. This study summarizes the methods and parameters used to estimate permeability using NMR signals from hydrate-bearing sediment obtained from logging and laboratory tests for the Gulf of Mexico and Alaska North Slope. In addition, we reports parameters for predicting model for muddy sediments which was recovered from overburden of hydrate-reservoir in the Hyuganada sea in 2022 Japan [10, 11]. When using the hydraulic radius model to predict permeability of hydrate-bearing sediment, reasonable estimates can be obtained by setting the shape factor for grains Cs = 1/2 (for a circular grain) and the shape factor for the flow path cn = 4 (for the cylinder network), respectively. Although, for hydrate free muddy sediment, Cs = 1/3 for parallel plate grain shape and cn = 2 for the fracture network model matched its permeability. Furthermore, the conversion parameter from T2 relaxation time to the pore size for hydrate free muddy sediments r2 = 0.009 (mm/s) was confirmed based on the result of mercury injection capillary pressure analysis, which is lower than r2 = 0.0325 (mm/s) of hydrate-bearing sediments.

Lithofacies and Shale Oil Potential of Fine-Grained Sedimentary Rocks in Lacustrine Basin (Upper Cretaceous Qingshankou Formation, Songliao Basin, Northeast China)

Shale oil has become a global hotspot of unconventional exploration and development. In this study, the latest drill core and experiment analyses of the Qingshankou Formation in the northern Songliao Basin were used to evaluate its lithofacies classification, sedimentary environment, pore types, pore-throat structure characterization, and shale oil potential. Lithofacies classification was determined according to the total organic carbon (TOC) content, sedimentary structure, and rock mineral content. Laminae genesis and micro-sedimentary structures indicate the deposition of fine-grained sedimentary rocks (FGSRs) in a semi-deep to deep lacustrine environment; however, evidence also suggests partial reworking by storm events and bottom current flows. FGSRs mostly comprise type I kerogen, with small amounts of type II1. The average vitrinite reflectance of the FGSRs was 1.37%, indicating middle to high stages of thermal maturation within the oil generation window. The N2 adsorption experiment indicated that silty mudstone (SM), silty fine mixed sedimentary rock (SFMR), and argillaceous fine mixed sedimentary rock (AFMR) had ink-bottle-shaped and slit-shaped pores, and the lithofacies were dominated by mesopores, accounting for 77.4%, 71.9%, and 80.8% of the total pore volume, respectively. Mercury injection capillary pressure analysis indicated that SM and SFMR had an average pore-throat radius of 0.01–0.04 μm, whereas AFMR and CM were dominated by nanopores, mainly distributed in the range of 0.004–0.0063 μm. Based on the comprehensive studies of TOC content, pore development, and brittleness, we concluded that organic-rich laminated SM and SFMR should be the focus of shale oil exploration of the Qingshankou Formation in the northern Songliao Basin, followed by organic-rich or organic-moderate laminated and layered AFMR, as well as calcareous fine mixed sedimentary rocks.

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

Pore Structure and Seal Capacity of Ilaro Formation Shales in the Eastern Dahomey Basin: Implications from Mercury Injection Capillary Pressure and Spontaneous Imbibition Analyses

A petrophysical evaluation of caprock pore characteristics and seal capacity is critical for geologic storage of CO2. In this study, integration of X-ray diffraction, mercury injection capillary pressure (MICP), and spontaneous imbibition analyses is used to evaluate the pore characteristics and seal capacity of shale samples from the Ilaro formation, which could serve as a seal for CO2 injected into the reservoir units of the eastern Dahomey basin. X-ray diffraction reveals the samples as clay-rich and early diagenetic, while spontaneous imbibition reveals pore connectivity heterogeneity. MICP analysis shows the samples as being characterized by a low breakthrough pressure and reveals the mesopore dominance with majority of pore volumes dominated by 5 to 10 nm-sized pore throats. Furthermore, high CO2 column heights are obtained from conversion of MICP data (at 20% saturation) for mesopore-dominated samples containing ankerite and kaolinite. The study reveals that should injected CO2 migrate upward from the reservoir units of the onshore eastern Dahomey basin, portions of the Ilaro formation may function as a good seal due to the mesopore mineralogical composition influence on the CO2–brine–rock interaction. This result should therefore serve as an important insight for future caprock sealing studies conducted on the onshore eastern Dahomey basin.

Fluid distribution in a tight gas reservoir using the saturation-height model

The development of tight gas reservoirs requires detailed knowledge of gas volumes and their distribution in three-dimensional space. This information can be obtained using a Saturation Height Model (SHM) developed by combining mercury injection capillary pressure analysis and well logging data. The SHM is constructed using core data from two wells in the tight gas reservoir of Amin formation in Oman.The saturation-height model is represented by a tangent line function linked with porosity. The developed SHM accurately simulates water saturation from well logs in seven wells. The curve fitting procedure determines three baselines, designated as free water levels (FWL), increasing with depth in the order of FWL0, FWL1 and FWL2.In three wells, the best match for the water saturation curve is obtained using FWL1 for Upper Amin formations and FWL2 for Low and Middle Amin formations. Different FWLs in the wells indicate differences in well placement within blocks and depending on tectonic history.The described tight gas reservoir can rather be characterized as a composite type because gas accumulations are not only found in high positions, but they also exist deeper over a wide range of depths.The developed SHM and the determined FWLs can be used for 3D reservoir modeling, in situ gas volumetric analysis and Sw calculation in undrilled areas to formulate a field development plan and fracturing program. This information makes it possible to estimate the consumption of water and chemicals required for hydraulic fracturing operations, which, in turn, makes it possible to estimate the required capacities for treatment of produced water and gas and to identify the places of possible contamination and gas losses.

Petrophysical Characterizations of Shale Gas Reservoirs of the Ranikot Formation in the Lower Indus Basin, Pakistan

The complex pore structure with nano-pores of shale gas reservoirs has an impact on the hydrocarbon storage and transport systems. We examined the pore structure of the shales of the Ranikot Formation in the Lower Indus Basin, Pakistan to investigate the full scaled pore size distributions by using a combination of techniques, mercury injection capillary pressure analysis and low pressure gas adsorption methods using N2 and CO2. Isotherm curves obtained N2 and CO2 adsorptions were interpreted using density functional theory analysis for describing the nano-scaled pore size distributions. The pore geometry of the shales was estimated to be slit-type from the isotherm hysteresis loop shape. The pore size distributions determined the density functional theory showed the dominant pore size of below around 10 nm. The Micro-scale effects such as slippage and adsorption/desorption also significantly influence the gas flow in nano-pore structure. The gas flow regimes in shales are classified into four types Darcy flow, slip flow, transition flow, Knudsen flow based on the value of the Knudsen number. Applying the specific reservoir conditions in Ranikot shale and pore size distribution to the Knudsen number, the gas flow regimes of the Ranikot shales were estimated mostly within the transition and slip flow.

An innovative image-based workflow for quantitative pore structure characterization in reservoir rocks

Pore connectivity is a key parameter to affect reservoir quality (e.g. permeability). Routinely, this parameter is assessed with special core analysis (i.e. mercury injection capillary pressure analysis). In this paper, an innovative image-based pore structure workflow is proposed to quantitatively delineate the connectivity of pore space of reservoir rocks by using widely available thin section images. By borrowing the concept of mercury injection capillary pressure (MICP), this workflow is able to generate pseudo MICP curves that can be used to quantitatively characterize pore throat/body size distribution and pore connectivity of pore networks. This workflow consists of four steps: (1) HSV threshold-based pore identification; (2) K-D tree structure-based pore segmentation; (3) enhanced watershed-driven pore throat detection, and (4) pore throat distribution generation derived with a media-axis-maximal-circle algorithm. The pseudo MICP curves generated by the workflow can be used to quantitatively assess the variations in pore size, pore throat size, pore geometrical complexity as well as the density of pores of reservoir rocks. Two connectivity indices derived from pseudo MICP curves are introduced to evaluate the connectivity of pore network of reservoir rocks. This workflow provides an innovative and efficient tool for geologists and reservoir engineers to perform quantitative reservoir rock quality evaluation by utilizing widely-available thin section images.

Effect of Particle Size on Pore Characteristics of Organic-Rich Shales: Investigations from Small-Angle Neutron Scattering (SANS) and Fluid Intrusion Techniques

The sample size or particle size of shale plays a significant role in the characterization of pores by various techniques. To systematically investigate the influence of particle size on pore characteristics and the optimum sample size for different methods, we conducted complementary tests on two overmature marine shale samples with different sample sizes. The tests included small-angle neutron scattering (SANS), gas (N2, CO2, and H2O) adsorption, mercury injection capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging. The results indicate that artificial pores and fractures may occur on the surface or interior of the particles during the pulverization process, and some isolated pores may be exposed to the particle surface or connected by new fractures, thus improving the pore connectivity of the shale. By comparing the results of different approaches, we established a hypothetical model to analyze how the crushing process affects the pore structure of overmature shales. Our results imply that intact wafers with a thickness of 0.15–0.5 mm and cubic samples (~1 cm3) are optimal for performing SANS and MICP analyses. Meanwhile, the 35–80 mesh particle size fraction provides reliable data for various gas physisorption tests in overmature shale. Due to the intrinsic heterogeneity of shale, future research on pore characteristics in shales needs a multidisciplinary approach to obtain a more comprehensive, larger scale, and more reliable understanding.

Controls on reservoir properties in organic-matter-rich shales: Insights from MICP analysis

Mercury injection capillary pressure (MICP) analysis was used to study organic-matter-rich Devonian shales varying in maturity from marginally mature to postmature to discuss controls on drainage and imbibition in shale reservoirs. Six samples come from the New Albany Shale; their total organic carbon (TOC) ranged from 3.3 to 8.4% and vitrinite reflectance (Ro) from 0.54 to 1.42%. One Marcellus Shale sample with Ro 2.50% was used to extend the maturity range to the advanced dry gas window. Three coal samples of varying rank were also included for comparison. Porosity of the shales ranges from 1.5 to 5.0%, and MICP-derived permeability ranges from 0.17 to 9.9 mD. Injection capillary pressure curves have a range of entry pressures from 0.055 to 0.421 MPa, and no relationship of entry pressure with maturity was revealed. Maturity, however, has an influence on pore size distribution, with the higher-maturity samples having significantly lower volumes of pores with throats less than 10 nm in diameter. Withdrawal capillary pressure curves document a wide range of withdrawal efficiencies from 55% to almost 100%, and pores having throats between 3 and 50 nm in diameter play a major role in the ability of mercury to be released from the pore system. The obtained data provide valuable information about shale properties and their behavior not only in the air-mercury system but also under reservoir conditions.

Generating pseudo-capillary pressure curves from nuclear magnetic resonance (NMR) data: a case study from the Cooper Basin, Australia

This study evaluates the accuracy of generating pseudo-capillary pressure curves from laboratory nuclear magnetic resonance (NMR) analysis and NMR wireline log data by comparing threshold pressures and curve characteristics to rock-derived mercury injection capillary pressure (MICP) analysis. Accurate production of pseudo-capillary pressure curves from NMR data could negate or reduce the need for expensive and rig-time-consuming core acquisition and subsequent MICP analysis. Successful application of this technique will allow production of pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost and help to better constrain petroleum reserves and improve near field exploration prediction outcomes. The Tindilpie-11 well in the Cooper Basin, Australia, was used as a case study because of extensive existing conventional ore analysis and presence of an NMR wireline log covering the sampled intervals in the Permian-aged Patchawarra Formation. Six core samples underwent MICP and laboratory NMR analyses, with capillary pressure curves generated for each method. Six pseudo-capillary pressure curves were also generated from the NMR wireline log data at the coincident sample depths. The pseudo-capillary pressure curves generated from laboratory NMR data closely resemble the MICP results (mean threshold pressure error of 0.63 MPa absolute [91.4 psi]) and proved the applicability of this approach. The NMR wireline log data used is an average over a ∼1.6 m interval, which has likely led to discrepancies when compared with laboratory NMR pseudo-capillary pressure curves and MICP curves. Nonetheless, this study confirms the applicability of using laboratory NMR data to generate pseudo-capillary pressure curves that resemble MICP results. Continued development of NMR log technology and reduced logging speeds will improve the data resolution and ultimately provide high density NMR data that can be used to create pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost. KEY POINTS Pseudo-capillary pressure curves derived from NMR data. Reservoir characterisation requiring minimal rock acquisition for ground truthing. Case study on the Patchawarra Formation (Cooper Basin, Australia) using SCAL data.

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.

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.

Insights into deep, onshore Gulf of Mexico Wilcox sandstone pore networks and reservoir quality through the integration of petrographic, porosity and permeability, and mercury injection capillary pressure analyses

In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.

Pore fractal model applicability and fractal characteristics of seepage and adsorption pores in middle rank tectonic deformed coals from the Huaibei coal field

Middle rank tectonic deformed coal samples were screened from the Xutuan and Qinan coal mine in the Huaibei coal field, Anhui Province, North China. Based on mercury injection capillary pressure analysis and nitrogen sorption experiments using the Brunuaer-Emmett-Teller analysis, pore structure characteristics and applicability of the Sierpinski, Menger, Thermodynamics, and Frenkel-Halsey-Hill models for seepage and adsorption pore description were analyzed, as well as the fractal characteristics of the two types of pores. Several conclusions have been achieved. 1) The Sierpinski model can characterize the heterogeneity of seepage pores in tectonic deformed coals, and the thermodynamic model can be used for referencing and comparative analysis. The Frenkel-Halsey-Hill model can be used to describe the heterogeneity of adsorption pores, and the Sierpinski model can be a supplement. However, the Menger model is not suitable for characterizing the pore heterogeneity of coal because its fractal dimension exceeds three, and the standard deviation is larger than the others. 2) The fractal dimension of adsorption pores increases while seepage pores decreases, with the enhancement of tectonic deformation. The heterogeneity of adsorption pores in the cataclastic, schistose and scaly coals are weaker than that of seepage pores (Ds2<Ds1), the heterogeneity of the adsorption pores in wrinkle coal is similar to that of seepage pores (Ds2≈Ds1), whereas the adsorption pores' heterogeneity in mylonitic coal is stronger than that of seepage pores (Ds2>Ds1).

Petrographic and Petrophysical Characterization of Detrital Reservoir Rocks for CO2 Geological Storage (Utrillas and Escucha Sandstones, Northern Spain)

The aim of this article is to provide a qualitative and quantitative description of Lower–Upper Cretaceous detrital rocks (Escucha and Utrillas sandstones) in order to explore their potential use as CO2 reservoirs based on their petrographic and petrophysical characteristics. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to get qualitative and quantitative information about mineralogy, texture and pore network structure. Complementary analyses by X-ray fluorescence (XRF) and X-ray diffraction (XRD) were performed to refine the mineralogical information and to obtain whole rock geochemical data. Furthermore, mercury injection capillary pressure analysis (MICP), the gas permeameter test (GPT) and the hydraulic test (HT) were applied to assess the potential storage capacity and the facility of fluid flow through the rocks. Both of these factors have an outstanding importance in the determination of CO2 reservoir potential. The applied petrophysical and petrographic methods allowed an exhaustive characterization of the samples and a preliminary assessment of their potential as a CO2 reservoir. The studied conglomerates and sandstones have a porosity range of 8–26% with a dominant pore size range of 80–500 μm. The grain skeleton consists of quartz (95%), very minor potassium feldspars (orthoclase) and a small amount of mica (muscovite and chlorite). According to these preliminary results, among the studied varieties, the Escucha sandstones have the most favorable properties for CO2 geological storage at the rock matrix scale.

Pore structure, wettability, and spontaneous imbibition of Woodford Shale, Permian Basin, West Texas

Even after more than 30 years of exploration and production, low total recovery of shale gas (<30%) and tight oil (5%–10%) constrains sustainable shale hydrocarbon development in the United States. Since the Woodford Shale is one of the principal source rocks of the Permian Basin, West Texas, this study uses core samples of Woodford Shale from the Reliance Triple Crown (RTC) #1 well in Pecos County, Texas, to examine mineralogy, pore structure, wetting characteristics, imbibition behavior, and edge-accessible porosity with the following complementary tests: X-ray diffraction (XRD), mercury injection capillary pressure (MICP), contact angle measurement of various fluids, fluid imbibition into initially-dry shale, and edge-accessible pore connectivity from vacuum saturation-high pressure impregnation with tracers-containing n-decane. The wettability and imbibition tests use both polar (hydrophilic, deionized water) and nonpolar (hydrophobic, n-decane) fluids. Our results indicate that Woodford Shale samples (Upper, Middle, and Lower Members) have different geologic (mineralogy) and reservoir (e.g., total organic carbon, porosity, and permeability) characteristics. MICP analyses show that the median pore-throat diameters for the Woodford Shale are 3.7–5.4 nm, and almost 70–80% of pore-throats by volume are smaller than 100 nm, with high tortuosity for fluid flow and mass movement. Spontaneous fluid imbibition into Woodford Shale exhibits imbibition slopes (from the plots of log imbibition vs. log time) close to ¼ for deionized water and ½ for n-decane, consistent with contact angle measurements that indicate a marginally water-wet, but very strong oil-wet, nature for these shales. Edge-accessible pore connectivity tests indicate that well-connected hydrophobic pore networks (primarily organic matter-hosted pores) have pore-throat sizes of approximately 5 nm and experience molecular entanglement with nm-sized tracers used in vacuum saturation tests. Our analyses suggest that the middle Woodford member will be the best interval for stimulation and hydrocarbon production. The findings from these complementary experimental approaches suggest low connectivity of tortuous nanopore networks and mixed-wet characteristics, which could have implications for total hydrocarbon recovery in Woodford Shale.

An investigation of the effect of CO2–brine–rock interaction on determination of Archie's saturation exponent for carbon dioxide evaluation in carbonate reservoirs

Accurate evaluation of reservoir fluid in place using electrical resistivity logs depends on accurate laboratory measurements of Archie parameters. Sensitivity of resistivity-based saturation models on these parameters, and their determination in non-Archie rocks have been extensively discussed in numerous technical papers. Conventional estimation of saturation exponent involves either steady state or porous plate displacement methods whereby a non-wetting phase displaces the wetting phase. When applying this technique in carbon dioxide sequestration projects in order to estimate and monitor carbon dioxide (CO2) accumulation in underground saline carbonate aquifer, it becomes imperative to consider the effect of CO2–brine–rock interaction (CBRI) since carbonic acid formed after dissolution of CO2 in formation brine will dissolve some soluble carbonate grains thereby altering rock pore structure and possibly change saturation exponent as CO2 sequestration lasts. In this paper, we investigated the effect of CBRI on Archie’s electrical parameters. Systematic laboratory procedures were designed to study saturation exponent and cementation factor for samples with and without CO2 sequestration taking into account the effect of hysteresis and measurement errors. State of the art characterization techniques like nuclear magnetic resonance (NMR) and mercury injection capillary pressure (MICP) were used to characterize and select core plugs of most similar pore character from a set of plugs obtained from a homogeneous Indiana limestone core. Saturation exponents and cementation factors of samples in which CO2 were sequestered were found to be different from other samples with the same pore structure but without CO2 sequestration. Saturation exponent for the sample in which CO2 was not stored was 1.46, while for those samples in which CO2 was stored, saturation exponent was found to be in the range of 1.65–5.68 with a corresponding porosity increase also in the range of 5–10%. Cementation factors were also found to decrease slightly from 1.44 to between 1.29 and 1.38. The extent of the variation in saturation exponent depended on the time of storage and the degree of CBRI in each sample. Post CO2 sequestration NMR and MICP analysis also confirmed altered pore character in the storage samples. Some of the dissolved calcite minerals were also seen as precipitates in brine effluents after CO2 storage.

Organic matter/clay mineral intergranular pores in the Lower Cambrian Lujiaping Shale in the north-eastern part of the upper Yangtze area, China: A possible microscopic mechanism for gas preservation

Gas shales with a high gas content were encountered in the Lower Cambrian Lujiaping Formation in the northeast part of the upper Yangtze area, China. In this area, the tectonic condition is complex and the organic matter is over-matured, so conventional oil and gas exploration have not previously been considered. During a recent shale gas exploration, canister-desorbed gas contents of more than 1 m3/t were detected from 490 to 825 m depth, with a maximum value of 3.18 m3/t at 762 m. Hence to understand the mechanism of preservation of the gas is important. The gas shales have a total organic carbon (TOC) content of between 0.44% and 6.91%, and vitrinite-like macerals reflectance (Ro) between 3.3% and 4.3% with type II kerogen. The porosity of 22 gas shale samples ranges between 0.4% and 2.29%, and their permeability is between 6.9 × 10− 5 and 3.8 × 10− 1 mD. To investigate the shale's pore structure and its relation to gas storage behavior, we studied the microscopic mechanism of gas preservation using a combination of pore characterization techniques, including focused ion beam-scanning electron microscope (FIB-SEM) imaging, and comparison of gas sorption and free gas storage capacity. Folding, thrusting and subsequent rapid uplifting movements occurred after most of the dry gas had been originally generated, and the present gas is a mixture originated from the cracking of liquid hydrocarbons at high maturity and kerogen pyrolysis in the early hydrocarbon-generation phase. SEM observations, combined with low temperature gas adsorption and mercury injection capillary pressure analyses, show that pores within the organic matter or the mineral particles in the Lujiaping Shale are rare, while the nanometer-sized pores (1–4 nm) between organic matter and clay mineral particles, especially in cleavage domains, are greatly developed. Thus the gas in these shales is mainly adsorbed gas due to the limited free gas storage space. This is unlike most other shale gas reservoirs, pores within the organic matter and pores between or within mineral particles are dominant. Moreover, the desorbed gas content correlates well with TOC content and the microporous and mesoporous specific surface area determined by low temperature CO2 and N2, respectively, suggesting that the nanometer-sized pores associated with the organic matter make up the fundamental storage space for this shale. The calculations based on FIB-SEM observation showed that the nanometer-sized intergranular pores have large specific surface areas, with their small pore throat diameters resulting in high capillary pressure. These characteristics have contributed to the preservation of shale gas in this complex tectonic area.

Textural and sequence-stratigraphic controls on sealing capacity of Lower and Upper Cretaceous shales, Denver basin, Colorado

Shale units can be important barriers to fluid flow in sedimentary basins and commonly serve as seals to petroleum reservoirs. Little is known, however, about the controls on shale permeability. Consequently, variation in seal competency is one of the greatest risk factors associated with petroleum exploration.Here, we examine possible controls on sealing capacity in two Cretaceous marine shale units in the Denver basin, Colorado. Sealing capacity, as determined by mercury injection–capillary pressure analysis, is compared to several textural and compositional parameters and to sequence-stratigraphic setting. These two shale units display highly variable sealing capacity, even between some adjacent samples. This suggests that variability in some small-scale shale characteristics may strongly influence sealing capacity. The best seals are generally in transgressive systems tracts, especially within or immediately below condensed sections.Textural characteristics of shale appear to be especially important in determining sealing capacity. In particular, well-sorted pore-throat sizes and well-developed bedding-parallel preferred orientation of flattened organic matter particles strongly favor high sealing capacity. High degrees of bioturbation degrade sealing capacity, possibly by disrupting preferred orientation and by increasing variability in grain size and hence in pore-throat sorting. Preferred orientation of matrix clays parallel to bedding also appears to increase with increasing sealing capacity, but is probably less important than the preferred orientation of organic matter.Compositional characteristics are generally less important than textural characteristics in determining sealing capacity in these shale units. Neither silt content nor cement content appears to be important to sealing capacity in these shale units. Total organic carbon is generally high in samples with good sealing capacity, but can be either high or low where sealing capacity is poor.Overall, the variables that most strongly favor high sealing capacity, pore-throat sorting, organic matter bedding-parallel preferred orientation, and low bioturbation, are most likely in anoxic, deep-water settings, hence, the association between good seals and condensed sections.

Trap and Seal Analysis in Carbonate Shelf Margin Stratigraphic Trap Exploration; Example from the Lower Miocene, Zhujiang Formation, Pearl River Mouth Basin, People's Republic of China: ABSTRACT

Carbonate shelf margin stratigraphic traps are a particularly risky play type because the same diagenetic factors responsible for secondary reservoir quality enhancement can be responsible for degrading seal quality and increasing trap risk. The Zhujiang Fm. prograded westward off the Dongsha Massif initially as a ramp which evolved into a prograding and aggrading shelf margin. Seismic interval velocity analysis, modeled with data from a nearby oil-bearing pinnacle reef, indicates a thick porosity zone at the shelf margin, wedging and pinching out eastward. Core data from the pinnacle reef indicated a short-term exposure event was responsible for significant early secondary porosity enhancement. This also may have influenced the adjacent shelf area; enhancing porosity in the shelf margin, but reducing seal capacity in the equivalent up-dip shelf sequence. The seal competency of the overlying Hanjiang shales was demonstrated by hydrocarbons sealed in the adjacent pinnacle reef. Seal risk was evaluated by mercury injection capillary pressure analysis in a shelf carbonate well updip from the margin. It was determined that the up-dip shelf seal is sufficient to hold an economically favorable 300-500 ft (90-150 m) hydrocarbon column. Seismic evidence revealed several large mega-slumped portions of the shelf margin producing scalloped areas extending severalmore » kilometers back into the shelf. Subsequent filling of these reentrants could produce lateral sealing by juxtaposing Hanjiang shales against the sides of the remnant Zhujiang carbonate salient. The slump scar on the south side of the salient did not downcut to a significant stratigraphic depth to provide a critical closure to trap a minimum hydrocarbon column to meet economic thresholds.« less