Unlike conventional oil production methods, enhanced oil recovery (EOR) processes can recover most oil products from the reservoir. One method, known as wettability alteration, changes the hydrophilicity of the reservoir rock via decreased surface interactions with crude oils. The mitigation of these attractive forces enhances petroleum extraction and increases the accessibility of previously inaccessible rock deposits. In this work, silica nanoparticles (NPs) have been used to alter the wettability of two sandstone surfaces, Berea and Boise. Changes in wettability were assessed by measuring the contact angle and interfacial tension of different systems. The silica NPs were suspended in brine and a combined solution of brine and the Tween®20 nonionic surfactant at concentrations of 0, 0.001, and 0.01 wt% NP with both light and heavy crude oil. The stability of the different nanofluids was characterized by the size, zeta potential, and sedimentation of the particles in suspension. Unlike the NPs, the surfactant had a greater effect on the interfacial tension by influencing the liquid-liquid interactions. The introduction of the surfactant decreased the interfacial tension by 57 and 43% for light and heavy crude oil samples, respectively. Imaging and measurements of the contact angle were used to assess the surface-liquid interactions and to characterize the wettability of the different systems. The images reflect that the contact angle increased with the addition of NPs for both sandstone and oil types. The contact angle in the light crude oil sample was most affected by the addition of 0.001 wt% NP, which altered both sandstones’ wettability. Increases in contact angle approached 101.6% between 0 and 0.001 wt% NPs with light oil on the Berea sandstone. The contact angle however remained relatively unaffected by addition of higher NP concentrations, thus indicating that low NP concentrations can effectively be used for enhancing crude oil recovery. While the contact angle of the light crude oil plateaued, the heavy crude oil continued to increase with an increase in NP concentration; therefore indicating that a maximum contact angle in heavy crude oil was not yet achieved. The introduction of NPs in light and heavy crude oil samples altered both the Berea and Boise sandstone systems’ wettability, which in turn indicated the efficacy of the silica NPs and surfactants in generating a more water-wet reservoir. Consequently, silica NPs and surfactants are most promising for EOR across the range of oil types.
Shales are heterogeneous media with porosity at many scales and in many microtextural positions, including within organic matter and clay aggregates. Because these materials have contrasting mechanical properties, it remains unclear how induced fractures manage to connect with this porosity whether during hydrocarbon production, wastewater injection, or carbon‐capture‐and‐storage efforts. To explore porosity changes related to fracturing, we experimentally failed shale samples in a triaxial load apparatus and observed changes in microstructure through scanning electron microscopy, low‐pressure nitrogen sorption, and nuclear magnetic resonance. We observed a system of microcracks, many of which were likely experimentally induced and localized on grain boundaries. In some cases these fractures propagated into regions of natural porosity in organic matter. In the subsurface this “fracture capture” likely enhances pore connectivity, but only selectively depending upon mechanical conditions. Fracture capture is one possible mechanism by which multiscale compositional heterogeneity in shales may affect rheological heterogeneity.
The goal of this study is to computationally determine the potential distribution patterns of diffusion‐driven methane hydrate accumulations in coarse‐grained marine sediments. Diffusion of dissolved methane in marine gas hydrate systems has been proposed as a potential transport mechanism through which large concentrations of hydrate can preferentially accumulate in coarse‐grained sediments over geologic time. Using one‐dimensional compositional reservoir simulations, we examine hydrate distribution patterns at the scale of individual sand layers (1–20 m thick) that are deposited between microbially active fine‐grained material buried through the gas hydrate stability zone (GHSZ). We then extrapolate to two‐dimensional and basin‐scale three‐dimensional simulations, where we model dipping sands and multilayered systems. We find that properties of a sand layer including pore size distribution, layer thickness, dip, and proximity to other layers in multilayered systems all exert control on diffusive methane fluxes toward and within a sand, which in turn impact the distribution of hydrate throughout a sand unit. In all of these simulations, we incorporate data on physical properties and sand layer geometries from the Terrebonne Basin gas hydrate system in the Gulf of Mexico. We demonstrate that diffusion can generate high hydrate saturations (upward of 90%) at the edges of thin sands at shallow depths within the GHSZ, but that it is ineffective at producing high hydrate saturations throughout thick (greater than 10 m) sands buried deep within the GHSZ. Furthermore, we find that hydrate in fine‐grained material can preserve high hydrate saturations in nearby thin sands with burial.
We report a new way of storing CO2 in a highly porous hydrate structure, stabilized by silica nanoparticles (NPs). Such a porous CO2 hydrate structure was generated either by cooling down NP-stabilized CO2-in-seawater foams, or by gently mixing CO2 and seawater that contains silica NPs under CO2 hydrate-generating conditions. With the highly porous structure, enhanced desalination was also achievable when the partial meltdown of CO2 hydrate was allowed.
We performed uniaxial, constant-rate-of-strain consolidation experiments and grain size analyses to characterize the transport and deformation properties of eight samples from Integrated Ocean Drilling Program Expedition 341 Sites U1420 and U1421. Permeability, compression indexes, and swelling indexes were determined from consolidation experiments. Permeability values range from 1.2 × 10–17 m2 to 2.0 × 10–13 m2, are positively correlated with median grain diameter, and exhibit little depth dependence. Compression indexes, which define stress-strain behavior during virgin consolidation, range from 0.13 to 0.25 and are negatively correlated with median grain diameter. Swelling indexes, which define stress-strain behavior during elastic reconsolidation, range from 0.023 to 0.036 and are best correlated with compression indexes, generally being equal to 16.8% of the compression index value. Median grain diameters determined by Stokes settling analysis range from 0.00232 to 0.0969 mm, with samples consisting of roughly equal portions of sand, silt, and clay. The standard deviations of the grain size distributions indicate that the sediment grains are very poorly sorted.
The intense sampling and testing effort has built a substantial data set to address questions concerning the evolution of permeability during early burial and subduction. On the other hand, current data sets are limited to a handful of subduction zone transects, and samples are primarily from depths of approximately 1 km or less. This depth range examines the transition from unconsolidated near‐seafloor sediment to those with porosities <0.3. Because an important aim of subduction zone research is to understand seismogenic processes, permeability‐porosity relationships have been extended by testing of samples during consolidation. In this chapter, the existing data from subduction zone sediments are analyzed. Sampled subduction zones include the Kumano, Muroto, and Ashizuri transects offshore southwest Japan, the Tohoku region near the Japan Trench, the northern Barbados accretionary prism, the Cascadia accretionary prism offshore Oregon, the Peru Margin, and the Nicoya and Osa Peninsulas offshore Costa Rica.
Critical path analysis (CPA), originally developed to describe electrical conductance in semiconductors, has been shown recently to hold some promise in describing transport properties of porous media. I applied some previously developed concepts in CPA and percolation theory to predict permeability in a suite of sandstone, carbonate, and clay-rich samples. I assumed that the pore sizes in my samples exhibited fractal scaling and expressed the electrical formation factor as a function of porosity using universal scaling from percolation theory. The resulting CPA permeability predictions match the measured values very well. In addition, I show how considering the scale-dependence of the percolation threshold yields two characteristic length scales for transport properties: the critical pore size, and the sample size. This work suggests that the CPA framework is appropriate for describing transport properties of natural porous media, and provides a theoretical basis for understanding the permeability of tight rocks like shale in which laboratory permeability measurements are difficult.
Nitrogen sorption isotherms measured at 77K are widely used for pore-scale characterization of shale and other porous materials with nanometer scale pore size range. We previously built a pore throat network for simulation of nitrogen sorption that modeled different types of pore size distribution and connectivity (specifically of porous media with bimodal pore sizes), but assumed spherical pore and cylindrical throat shapes. In a separate work, we recently applied a modified lattice density functional theory (LDFT) to adsorption modeling for pores with different shapes. The model was implemented for an ideal porous material with a uniform pore size. In this study we combine the pore network with LDFT theory to study the effects of pore size, shape, connectivity and surface chemistry heterogeneity on nitrogen adsorption and desorption isotherms. A multi-scale network model is modified with pores of bimodal size distribution (representing inter-granular, intra-granular and/or organic matter pores). LDFT theory is applied to every pore in the network. This model is further applied to sorption analysis of core samples from Woodford shale, Cameo coal and tight Middle East carbonate. By matching simulated nitrogen sorption curves with experimental ones, we obtain not only the pore size distribution, but also pore shape, connectivity and surface energy. Results show that for Cameo coal both slit and cylindrical pore networks give a good match, while for Woodford shale and tight Middle East carbonate, the best match is achieved with a cylindrical pore network. The developed model aids formation evaluation and reservoir productivity estimation. Parameters obtained from this model can serve as important input into reservoir-scale numerical simulators. Results on the effects of heterogeneity (pore size, shape, and surface energy) can be recorded in look-up tables, thus accelerating applications in petrophysical characterization.
Nuclear magnetic resonance (NMR) relaxation time distributions are frequently combined with mercury intrusion capillary pressure (MICP) measurements to allow determination of pore or pore throat size distributions directly from the NMR data. The combination of these two measurements offers an advantage over high-resolution imaging techniques in terms of cost and measurement time, and can provide estimates of pore sizes for pores below imaging resolution. However, the methods that are typically employed to combine NMR and MICP measurements do not necessarily honor the way in which the two different measurements respond to the size distribution and connectivity of the pore system. We present a method for combining NMR and MICP data that is based on percolation theory and the relationship between bond occupation probability and the probability that a bond is part of a percolating cluster. The method yields results that compare very well with pore sizes measured by high-resolution microtomography, and provides particular improvement in media with broad pore size distributions and large percolation thresholds.
The wettability of rocks is of fundamental importance to the understanding of fluid transport within hydrocarbon reservoirs. Wettability is intimately tied to the zeta potential, which is determined by the electrostatic forces among the rock's mineral constituents. Extensive prior research has been conducted into the relationship between wettability and surface forces of shale samples that have been ground up and/or otherwise been altered. However, very little attention has been given to measuring the zeta potential of the surface of unbroken, intact shale samples.
A new technique is explored in this paper that investigates the zeta potential of the actual surface of shale samples in one intact piece. The surface zeta potential of shales was found to be strongly determined by the mineral composition and the cation exchange capacity (CEC) of the shale. Shales containing higher amounts of silicates (e.g. quartz, feldspar, and clays such as Illite and Smectite) tended to be water-wet and exhibit higher negative zeta potential values. Shales that contained higher amounts of carbonates (dolomite, aragonite, calcite, etc.) were more oil-wet with zeta potential values that were less negative or slightly positive. Measurements were also performed on Berea and Boise sandstone in order to compare organic vs. inorganic samples. Results for common shales showed Mancos and Marcellus to be intermediate-wet, Oxford and Eagleford to be moderately oil-wet, and Arne to be highly water-wet. Additionally, the zeta potential was also studied in various ionic and nano-particle solutions.
Kerogen is an organic component of unconventional rocks. It is believed that the majority of the pore volume of tight rocks originates from the organic pore systems. Understanding the pore size distribution of these organic pores is instrumental to petrophysicists and geoscientists, as it provides valuable information on the reservoir properties. Nuclear magnetic resonance (NMR) has played a critical role in characterizing the pore systems both in core plugs and in reservoir formations. Although a considerable amount of research has been published focusing on NMR studies of sandstone and carbonate rocks, few studies have been reported for organic pore systems in shale. Of particular interest is the surface relaxivity, which is an essential parameter for estimating pore size distribution via NMR. To date, surface relaxivity of kerogen is only available via estimations based on SEM images of a small area or adsorption/imbibition experiments performed on whole shale core plugs. In this paper, we report a direct measurement of surface relaxivity on isolated kerogen powders.
Kerogen powders were extracted from shale plugs using non-oxidizing reagents. We used the ‘Pulsed Field Gradient’ (PFG) stimulated echo method to measure the apparent diffusion coefficients of the decane molecules, and then calculated the average surface to volume ratio by plotting the diffusion coefficients against the diffusion times. We then obtained the surface relaxivity through the correlation between transverse relaxation time and the calculated surface to volume ratio. The surface relaxivity of Barnett shale kerogen was determined to be 18.9 ± 6.54 μm/s. Based on this result, we further concluded that spherical pores with a diameter of 6 nm or smaller would not be detectable by a lab NMR system with a TE of 0.1 ms. The method was also applied to obtain kerogen surface relaxivity values from other shale formations. The direct measurement of kerogen surface relaxivity is of great importance in the determination of organic pore size distribution in tight rocks, which will in turn facilitate the calculation of capillary pressure, relative permeability and other important petrophysical properties.
Textural characterization is a critical step to assess and evaluate petrophysical properties of unconventional reservoirs, including shale-gas, coalbed and tight-gas systems. Gas adsorption, typically with N2 at 77 K or CO2 at 273 K, is the widely used method for such characterizations. To translate adsorption data into useful petrophysical quantities such as pore size, pore connectivity, and pore volume, one needs to exploit appropriate correlations to link molecular scale interactions and macro-scale phenomena. One important yet under-studied property of unconventional matrices is their true pore structure and its effects on fluid thermodynamics inside pore space. Herein, based on lattice density functional theory, we have developed a multilayer adsorption model with parameterized energy terms, to determine effects of pore shape and pore size (of shale and coal samples) on the thermodynamic state of reservoir fluid. The model is extended from its original slit pore geometry into cylindrical and spherical geometries to consider the effects of local pore curvature on adsorption energetics and uptakes mainly in mesopores (between 2 and 50 nm). In addition, the surface energy term is modified to consider the effect of the force field exerted by pore walls on both the adlayer and subsequent adsorbed layers. Modification of the energy term resulted in layer-by-layer, two-dimensional condensation followed by the final capillary condensation. The force field exerted by the pore walls together with local pore curvature shifted the condensation pressures toward lower relative pressures (P/P0). By applying the model to N2 porosimetry isotherms at 77 K for two reference samples, ordered mesoporous silica (SBA-15) and ordered mesoporous carbon (OMC), the model confirmed essentially cylindrical pore structure for both samples. The model was further applied to N2 at 77 K porosimetry isotherms of Woodford shale and Cameo coal samples, and identified the pore structures of the samples as dominated by cylindrical and slit pore geometries, respectively.
Current low oil price conditions have renewed the emphasis on drilling optimization, in order to save time drilling oil and gas wells and reduce operational costs. Rate of penetration (ROP) modeling is a key tool in optimizing drilling parameters, namely bit weight and rotary speed, for faster drilling processes. With a novel, all-automated data visualization and ROP modeling tool developed in Excel VBA, ROPPlotter, this work investigates model performance and the impact of rock strength on model coefficients of two different PDC bit ROP models: Hareland and Rampersad (1994) and Motahhari et al. (2010). These two PDC bit models are compared against a base case, general ROP relation developed by Bingham (1964) in three different sandstone formations in the vertical section of a Bakken shale horizontal well. For the first time, an attempt has been made to isolate the effect of varying rock strength on ROP model coefficients by investigating lithologies with otherwise similar drilling parameters. Additionally, a comprehensive discussion on the importance of selecting appropriate model coefficients bounds is conducted. Rock strength, accounted for in Hareland's and Motahhari's models but not in Bingham's, results in higher values of constant multiplier model coefficients for the former models, in addition to an increased RPM term exponent for Motahhari's model. Hareland and Rampersad's model is shown to perform best out of the three models with this particular dataset. The effectiveness and applicability of traditional ROP modeling is brought to question, as such models rely on a set of empirical coefficients that incorporate the effect of many drilling factors not accounted for in the model's formulation and are unique to a particular lithology.
Quantifying fluid flow through porous media hinges on the description of permeability, a property of considerable importance in many fields ranging from oil and gas exploration to hydrology. A common building block for modeling porous media permeability is consideration of fluid flow through tubes with circular cross section described by Poiseuille's law in which flow discharge is proportional to the fourth power of the tube's radius. In most natural porous media, pores are neither cylindrical nor smooth; they often have an irregular cross section and rough surfaces. This study presents a theoretical scaling of Poiseuille's approximation for flow in pores with irregular rough cross section quantified by a surface fractal dimension Ds2. The flow rate is a function of the average pore radius to the power 2(3‐Ds2) instead of 4 in the original Poiseuille's law. Values of Ds2 range from 1 to 2, hence, the power in the modified Poiseuille's approximation varies between 4 and 2, indicating that flow rate decreases as pore surface roughness (and surface fractal dimension Ds2) increases. We also proposed pore length‐radius relations for isotropic and anisotropic fractal porous media. The new theoretical derivations are compared with standard approximations and with experimental values of relative permeability. The new approach results in substantially improved prediction of relative permeability of natural porous media relative to the original Poiseuille equation.
This study presents a method of two‐dimensional scanning electron microscope image analysis that directly quantifies microporosity abundance in clay‐rich, fine‐grained sediments. The method is novel in that it is specifically designed to circumvent the challenge to porosity quantification posed by mineral surface charging and topographical artifacts created during Ar‐ion cross‐section polishing. It utilizes the finding that differences in circularity values can be used to distinguish micropores from blemishes in a thresholded image. This method is powerful because it is fast and provides a direct microporosity estimation technique to augment or replace experimental data. The pore size range to which the method is applicable is clear and can be selected depending on the application of the analysis. When used appropriately, the method can be implemented on microporous sediments and sedimentary rock in general. The method is developed using marine muds of Pliocene and Miocene ages from the Nankai margin (burial depths from approximately 200 to 1100 m). The close match between imaging‐derived microporosity and bulk N2 microporosity measurements shows that porosity in these young and relatively shallowly buried sediments is dominated by pores of sizes that can be imaged by scanning electron microscopy. In Kumano, forearc basin sediments of the Nankai Trough, results of this method show a significant increase in microporosity with burial depth, probably due to microporosity preservation during compaction and possibly early volcanic ash diagenesis.
Accurate prediction of the relative permeability to water under partially saturated condition has broad applications and has been studied intensively since the 1940s by petroleum, chemical, and civil engineers, as well as hydrologists and soil scientists. Many models have been developed for this purpose, ranging from those that represent the pore space as a bundle of capillary tubes, to those that utilize complex networks of interconnected pore bodies and pore throats with various cross‐section shapes. In this paper, we propose an approach based on the effective‐medium approximation (EMA) and percolation theory in order to predict the water relative permeability. The approach is general and applicable to any type of porous media. We use the method to compute the water relative permeability in porous media whose pore‐size distribution follows a power law. The EMA is invoked to predict the relative permeability from the fully saturated pore space to some intermediate water saturation that represents a crossover from the EMA to what we refer to as the “critical region.” In the critical region below the crossover water saturation Swx, but still above the critical water saturation Swc (the residual saturation or the percolation threshold of the water phase), the universal power law predicted by percolation theory is used to compute the relative permeability. To evaluate the accuracy of the approach, data for 21 sets of undisturbed laboratory samples were selected from the UNSODA database. For 14 cases, the predicted relative permeabilities are in good agreement with the data. For the remaining seven samples, however, the theory underestimates the relative permeabilities. Some plausible sources of the discrepancy are discussed.
Interest in silica nanoparticle-stabilized emulsions, especially those employing low-cost natural gas liquids (NGLs), has increased due to recent developments suggesting their use leads to improved conformance control and increased sweep efficiencies. When compared to conventional emulsion- stabilizing materials such as surfactants, nanoparticles are an inexpensive and robust alternative, offering stability over a wider range of temperature and salinity, while reducing environmental impact.
Oil-in-water emulsions with an aqueous nanoparticle phase and either a pentane or butane oil phase at a 1:1 volume ratio were generated at varying salinities for the observations of several emulsion characteristics. The effects of salinity on the stability of silica nanoparticle dispersions and NGL emulsions were observed. Increasing the salinity of the aqueous nanoparticle phase resulted in an increase in effective nanoparticle size due to increased nanoparticle aggregation. Rheology tests and estimates of emulsion droplet sizes were performed. Shear-thinning behavior was observed for all emulsions. Furthermore, overall emulsion viscosity increased with salinity. Nanoparticle-stabilized liquid butane-in-water emulsions were also generated with varying brine concentrations; however, no rheology or droplet size measurements were made due to the volatility of these emulsions.
Residual oil recovery coreflood experiments were conducted (using Boise Sandstone cores) with nanoparticle-stabilized pentane-in-water emulsions as injectant and light mineral oil as residual oil. A recovery of up to 82% residual oil was observed for these experiments. By continuously measuring the pressure drop across the core, a possible mechanism for enhanced oil recovery is proposed. Pentane emulsion coreflood tests indicated that at a slower injection rate, residual oil recovery increases. This contrasts viscous emulsion corefloods (mineral oil or Texaco white oil as the emulsion oil phase), where increasing the injection rate increases the residual oil recovery.
Nuclear magnetic resonance (NMR) has been used as a common and powerful tool for petrophysical investigation of fluid-bearing porous media. A major complication of NMR analysis occurs, however, when diffusion of fluid protons through magnetic field heterogeneities becomes nonnegligible. A quantity called the secular relaxation rate (1/T2sec) has been defined as the difference in transverse and longitudinal relaxation rates (1/T2-1/T1) and can be shown to isolate the effects of diffusion as a function of pore system parameters. We have developed results that extract internal magnetic field gradient strengths based on changes in T2sec as a function of the NMR interecho spacing. We also indicated that an optimization algorithm can be used to invert for volumetrically weighted mean pore sizes. The benefit of these types of analyses is to provide simple methodologies for inferring the average strengths of internal magnetic field gradients and pore sizes from NMR measurements without the need for independent measurements of pore size, such as from mercury injection porosimetry. In addition, secular relaxation analysis removes complicating effects provided by bulk fluid and other nondiffusion relaxation mechanisms.
The removal of highly stable dispersed oil produced during oil recovery processes is very challenging, especially in offshore operations where the limited space does not allow use of equipment with long residence time for the required separation. Using magnetic nanoparticles (MNPs) to remove the dispersed oil from produced water is a promising way to overcome the difficulties that the current treatment technologies face, since the MNPs-attached oil droplets can be quickly and efficiently separated with application of an external magnetic field. The MNPs can be also regenerated and reused, minimizing the generation of hazardous waste. We investigated not only the optimal operating conditions, such as MNP concentration and salinity, but also the mechanisms of MNPs-oil attachment and magnetic separation.
We synthesized MNPs in the laboratory with a prescribed surface coating. The MNPs were superparamagnetic with an average individual particle size of ~10 nm. Crude oil content in separated water was reduced by as much as 99.9% using MNP concentrations as low as 0.04 wt% in 5 minutes after MNPs and oil were reacted.
The electrostatic attraction between negatively charged oil-in-water emulsions and positively charged MNPs controls the attachment of MNPs to the droplet surface; and the subsequent aggregation of the electrically neutral MNPs-attached oil droplets plays a critical role for accelerated and efficient magnetic separation. The particle aggregation occurred fast, generally within one minute. Thus, the total magnetic separation time was dramatically reduced to as short as 1 second, contrary to that of free, individual MNPs where it took about 36~72 hours, depending on the MNP concentrations.
Model calculations of magnetic separation velocity, accounting for the MNP magnetization and viscous drag, show that the velocity of free Amine functionalized MNPs (A-MNPs) increases about 1~3 orders of magnitude as the particles get closer to the magnet depending on the particle size. The smaller the particles, the greater the effect of the magnetic field on the velocity. A typical operating condition would be when the size of the MNPs-oil droplet aggregates is grown to be greater than 360 nm. Then, the total magnetic separation time will be approximately 5 minutes.