Determination Of Capillary Pressure Research Articles

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Seal quality assessment is not only essential in petroleum systems studies but also in the context of other geo energy applications such as underground hydrogen storage. Capillary breakthrough pressure controls top seal capacity in the absence of faults or other discontinuities. In basins that lack measured capillary pressure data (e.g., from drill cores), regional compaction-porosity trends can be used as a first prediction tool to estimate the capillary properties of mudstones. Mathematical compaction models exist but need to be calibrated for each basin. This study aims to establish a compaction trend based on theoretical models, then compare it with theoretical maximum hydrocarbon column heights inferred from true measured capillary pressure curves. Middle to upper Miocene mudstone core samples from the Vienna Basin, covering a broad depth interval from 700 to 3400 m, were investigated by X-ray diffractometry, with an Eltra C/S analyzer, and by Rock–Eval pyrolysis for bulk mineralogy, total organic carbon, and free hydrocarbon contents. Broad ion beam—scanning electron microscopy, mercury intrusion capillary porosimetry, and helium pycnometry were applied to obtain pore structural properties to compare the mathematical compaction models with actual porosity data from the Vienna Basin. Clear decreasing porosity depth trends imply that mechanical compaction was rather uniform in the central Vienna Basin. Comparing the Vienna Basin trend to global mudstone compaction trends, regional uplift causing erosion of up to ~ 500 m upper Miocene strata is inferred. A trend of increasing Rock–Eval parameters S1 and production index [PI = S1/(S1 + S2)] with decreasing capillary sealing capacity of the investigated mudstones possibly indicates vertical hydrocarbon migration through the low-permeable mudstone horizons. This observation must be considered in future top-seal studies for secondary storage applications in the Vienna Basin.

Limiting pathways and breakthrough pressure for CO2 flow in mudstones

The sealing and integrity of caprocks is a critical issue in the geological sequestration of CO2. In this work, we integrate multiscale pore-size measurements and imaging techniques, to characterize macropores, microporosity, and their spatial connectivity of intact mudstone cores from an Enping oilfield in the South China Sea. Together with the information on mineral compositions, we propose clay regions in the absence of organic matter as limiting pathways for supercritical CO2 flows in the cores, which primarily consist of nanopores ranging from tens to hundred nm in diameter. The FIB-SEM tomography is used to obtain nanoporous structures of a representative domain of those limiting pathways. We simulate the primary drainage of supercritical CO2 displacing brine in the domain by using an in-house quasi-static pore-network model. The numerical predictions of capillary breakthrough pressure match the experimental data well. Our proposed method of determining capillary breakthrough pressure can substantially complement experimental measurements. Moreover, it has the potential to quantitatively link the multiscale porous structures of mudstone to its CO2 sealing.

Coupled multiphase flow, geochemical, and geomechanical modelling of the impact of shale interlayers on CO2 migration

The need to find sufficient capacity for geological carbon dioxide (CO2) storage to meet demand means less-than ideal, heterogeneous reservoirs need to be considered. Many such reservoirs are apparently compartmentalised by inter-layers, which may help, or hinder, CO2 migration and storage capacity, depending upon their nature. The impact of shale inter-layers of thicknesses below seismic resolution are generally neglected in plume migration simulations, but have been shown here to be important. Only simulations of plume migration that include coupling of all three of mass transport, geo-chemical and geo-mechanical processes together provide proper prediction of the barrier efficiency of relatively thin shale inter-layers. A series of feedback inter-actions between these three process types has been studied in detail, and, for example, leads to the unexpectedly higher barrier efficiency of thin inter-layers compared to slightly thicker inter-layers. The results show that capillary breakthrough pressure, diffusion processes and re-activation of natural fractures played a vital role in enhancing the migration of the CO2 plume via the thicker shale inter-layers towards the overburden. This paper identifies significant research gaps regarding the effects of complicated, intricate processes affecting shale inter-layer (or seal) integrity under realistic reservoir conditions.

Comparing Centrifuge, Steady-State and Semi-Dynamic Methods for Relative Permeability and Capillary Pressure Determination: New Insights

Relative permeability and capillary pressure are essential parameters for understanding multiphase flow in porous media and scenarios of production in oil or gas reservoirs. There are several experimental methods for determining the relative permeability curves: unsteady-state (USS), steady-state (SS), and semi-dynamic (SD) methods. Each method has advantages and weaknesses. Although the USS approach leads to fast data results, the interpretation neglects the capillary pressure effects and provides a limited amount of data points obtained after breakthrough. The SS method is time consuming but enables covering a wider range of saturation with data points if the test is well designed. The SD method may be more time consuming than the SS method but provides both relative permeability to the injected phase and capillary pressure. The relative permeability to the produced phase is then determined by numerical means. The main objective of this study was to compare the water-oil relative permeability curves obtained from the steady-state and semi-dynamic methods performed at reservoir conditions with live fluids. Carbonate core plugs of same rock type and same properties were selected for this experimental program. The samples were brought to the same irreducible water saturation at a constant brine-oil capillary pressure using a centrifuge before being dynamically aged with live oil. In addition to monitoring the average saturation using material balance (MB), a linear X-ray scanner was used for in-situ saturation monitoring (ISSM) along the core samples. The oil relative permeability from the SD method was simulated with fixed water relative permeability and capillary pressure by history-matching the oil production and the differential pressure signal. Two additional centrifuge tests on twin plug were performed in order to measure imbibition capillary pressure and oil relative permeability at pseudo-reservoir conditions. This comparative study shows that the SD method provides similar capillary pressure and oil relative permeability curves to those obtained by centrifuge methods. Even if all Kr curves are in an acceptable envelop, some differences are observed between SD and SS Kr curves: several investigative leads are given to explain this discrepancy. It is also shown that a better saturation method needs to be implemented, especially when dealing with heterogeneous rocks. While a more robust ISSM method is being tested at TOTAL, the results presented in this paper are very encouraging.

Remediation characteristics of surfactant-enhanced air sparging (SEAS) technology on volatile organic compounds contaminated soil with low permeability

Surfactant-enhanced air sparging (SEAS) is an effective technology for the remediation of volatile organic compounds contamination of medium and high-permeability soil, though applying SEAS to low-permeability soil contamination has rarely been explored. In this study, a series of two-dimensional physical model tests were designed to explore the feasibility and remediation characteristics of SEAS on low-permeability soil. In the test results, the incorporation and increase in surfactant concentration promoted air channel formation in the low-permeability soil, finally reduced the capillary breakthrough pressure and improved the airflow rate. The majority of the exhausted gaseous contaminants were distributed along the horizontal direction, differing from the results observed in medium and high-permeability soils. The exhausted gaseous contaminant concentration changed slightly when the sparging pressure and surfactant concentration increased at relatively low levels and increased as the sparging pressure and surfactant concentration increased further. Increasing the air sparging pressure without surfactant incorporation or with a low surfactant concentration cannot effectively remove the contaminant, while the removal efficiency can be enhanced with further increases in surfactant concentration. The discrete remediation characteristics had been confirmed during SEAS application on low-permeability soil, then the relationships between the ratios of remediation area and remediation extent under different surfactant concentrations and sparging pressures were established for remediation efficiency evaluation. Using this method, the discrete remediation characteristics can be recreated once the surfactant concentration and the sparging pressure were chosen. On the other side, targeted improvements in the remediation area or extent can be achieved by controlling the surfactant concentration and sparging pressure. Through this study, SEAS technology and the proposed evaluation method were successfully implemented in soil with hydraulic conductivity around 9E-7 m/s, which expanded the application scope of SEAS technology for contaminant removal.

A quick method for estimating pore throat radii of shale using a combination of pressure transmission and capillary breakthrough measurements

A rapid and easy to conduct methodology has been proposed for preliminary estimation of pore throat radii and permeability of tight rocks such as shale. Pressure transmission and capillary breakthrough pressure tests were performed on three different shales (A, B and C) to develop a modified Poiseuille equation to estimate shale permeability. This was made possible by correlating the pore throat radius obtained from the pressure transmission test with the pore throat radius obtained from the capillary breakthrough pressure test. Results show that the modified Poiseuille equation has successfully predicted shale permeabilities that were reasonable and fell within the acceptable range of known shale permeabilities reported in the literature. In order to verify the validity of the modified Poiseuille equation, three different shales D, E and F with unknown permeabilities were investigated. The estimated permeabilities for shales D, E and F using the modified Poiseuille equation matched, with the exception of few variations, those obtained by conventional pressure transmission testing. The few variations could be related to the fact that the contact angle was assumed to be zero in the modified Poiseuille equation.

Multiphase CO2-brine transport properties of synthetic fault gouge

Faults are key components in defining fluid migration pathways and seals in sedimentary basins. The sealing capacity of faults is closely related to the petrophysical and geomechanical properties of fault gouge. Clay smear, cataclasis, and diagenesis favor a high capillary breakthrough pressure and low permeability in clastic sediments, and therefore fault gouge seal. However, significant uncertainty remains in accurately predicting the sealing capacity of faults for CO2 storage. We conducted a series of experiments, including absolute permeability, breakthrough pressure, and post-breakthrough CO2 permeability measurements on synthetic fault gouge samples, made from homogeneous mixtures of Frio sand and Anahuac shale, lithofacies of tertiary sediments in the Gulf of Mexico basin. The results show that the permeability of synthetic fault gouge decreases by about one order of magnitude with increments of 10 wt% of clay (mostly smectite) from the Anahuac shale. Independent of clay content and bulk porosity, all permeability measurements scale with the void ratio of the clay fraction. The breakthrough pressure of synthetic fault gouge increases by approximately half order of magnitude with increments of 10 wt% clay. The samples with clay content above 40 wt% reach a breakthrough pressure equivalent to a (supercritical) CO2 column height of more than 100 m. The measurements on fault gouge properties are meaningful to quantitatively evaluate fault sealing capability and migration of buoyant fluids through faults in sand-shale sequences.

Evaluation of lacustrine mudstone top sealing capacity in the Lenghu-5 area, Qaidam Basin, Tibetan Plateau

Top seal capacity is one of the fundamental geological factors that must be considered during petroleum exploration. Based on thin section, low-pressure N2 adsorption, bulk mineralogy, X-ray diffraction (XRD), mercury injection experiment and pressure data, the sealing capacity, lithofacies, petrophysics, diagenesis, capillary breakthrough pressure, overpressure, and brittleness index characteristics of a lacustrine mudstone top seal from the Lenghu-5 area, Qaidam Basin, Tibetan Plateau was investigated. The bulk rock composition of the top seal was dominated by clay minerals with carbonate cements and has a gross mudstone to sandy mudstone lithofacies. The isotherms from low-pressure nitrogen adsorption tests which presents as reversed S-shaped, belong to type B and the characteristics of hysteresis loops indicating the silt-like pores in the samples. The pores of the mudstone top seals are predominantly mesopores according to the N2 adsorption and mercury injection experiment results. The cumulative mudstone thickness varies from 100 to 1400 m. The overpressured mudstone top seal in the Lenghu-5 area has three potential hydrocarbon preservation implications: overpressure cannot seal oil and gas, overpressure seals oil and gas directly, and overpressure seals oil and gas indirectly. The brittleness index (BI) values calculated by four methods based on the mineralogical composition of the mudstone top seals and the BI is higher at the top and bottom of the studied interval than in the middle mudstone layer. Based on the mud content, pore diameter, thickness, diagenetic stage, capillary breakthrough pressure, overpressure coefficient and brittleness index of the lacustrine mudstone, the top seal in the Lenghu-5 area is classified into four types: type I, II, III and IV, representing good to poor sealing capacities. The method for evaluation of the sealing capacity in this study can not only provide useful guidance for hydrocarbon exploration in Lenghu-5 area, Qaidam Basin, but also can be used in basins around the world by selecting the main influencing factors of sealing capacity in the basin.

Oil and gas enrichment patterns and major controlling factors for stable and high production of tight lacustrine carbonate rocks, a case study of Yingxi area in Qaidam Basin, West China

In recent years, sustained important discoveries of oil and gas exploration in the E 32 reservoir of Oligocene in the Yingxi area have been achieved, which revealed great exploration potential in Qaidam Basin. Based on core observations and systematic research on micro-petrological and structural characteristics, lithology, hydrocarbons enrichment patterns, and major controlling factors of stable and high production of the Oligocene reservoir in the Yingxi area of Qaidam were studied. The following findings were reported: (1) the lithology of the target layer is mainly lacustrine carbonate rocks, which can be divided into inter-salt and subsalt strata. In addition, many thick layers of halites widely developed in inter-salt strata. While thin layers of gypsum also developed scatteringly in the subsalt strata. (2) Fine-grained lacustrine carbonate rocks (including dark mudstone) were deposited under saline conditions, which not only are relatively the best quality source rock, but also developed a “dessert” dolomite reservoir. This set of strata is characteristic of “authigenic source rock and authigenic reservoir”. The upper salt layers have a strong sealing ability because of their very high capillary breakthrough pressure and plastic characteristics, and joints formed widely in the subsalt strata since stress concentration. The good matching relationship among all of the above factors led to the formation of favorable area for large-scale hydrocarbon accumulation in the subsalt strata. (3) The development of the matrix intercrystalline pores controls the scale of oil and gas reservoirs and stable production. Moreover, the development of fractures controls the enrichment of oil and gas reservoirs and high production. The research results have important guiding significance for further research on subsalt oil and gas distributing regularities, as well as further exploration deployment of E 32 in the Yingxi area.

Out–of–plane capillary pressure of technical textiles

Textile permeability characterization often follows an unsaturated approach, i.e. a dry textile is impregnated by a fluid and flow front movement is monitored. For permeability calculation based on Darcy‘s law, a pressure-driven injection is commonly applied. Depending on flow velocity, capillary pressure can also contribute to flow movement, which would lead to a calculation error if not considered. This again requires capillary pressure determination. In the present work, a novel measurement system for out-of-plane capillary pressure based on weight increase was developed and applied to characterize the out–of–plane capillary pressure of a random mat, a twill 2/2 woven fabric, and a biaxial non-crimp fabric (all glass fiber) at three different fiber volume contents. Silicone oil was used as measurement fluid. Capillary pressures ranged between 150 and 225 Pa.

CO2 breakthrough—Caprock sealing efficiency and integrity for carbon geological storage

Small pores in high specific surface clay-rich caprocks give rise to high capillary entry pressures and high viscous drag that hinder the migration of buoyant carbon dioxide CO2. We measured the breakthrough pressure and ensuing CO2 permeability through sediment plugs prepared with sand, silt, kaolinite and smectite, and monitored their volumetric deformation using high-pressure oedometer cells. The data show water expulsion and volumetric contraction prior to CO2 breakthrough, followed by preferential CO2 flow thereafter. Our experimental results and data gathered from previous studies highlight the inverse relationship between breakthrough pressure and pore size, as anticipated by Laplace’s equation. In terms of macro-scale parameters, the breakthrough pressure increases as the sediment specific surface increases and the porosity decreases. The breakthrough pressure is usually lower than the values predicted with average pore size estimations; it can reach ∼6.2MPa in argillaceous formations, and 11.2MPa in evaporites. The CO2 permeability after breakthrough is significantly lower than the absolute permeability, but it may increase in time due to water displacement and desiccation. Leakage will be advection-controlled once percolation takes place at most storage sites currently being considered. Diffusive and advective CO2 leaks through non-fractured caprocks will be minor and will not compromise the storage capacity at CO2 injection sites. The “sealing number” and the “stability number” combine the initial fluid pressure, the buoyant pressure caused by the CO2 plume, the capillary breakthrough pressure of the caprock, and the stress conditions at the reservoir depth; these two numbers provide a rapid assessment of potential storage sites. Unexpected CO2 migration patterns emerge due to the inherent spatial variability and structural discontinuities in geological formations; sites with redundant seal layers should be sought for the safe and long-term storage of CO2.

New Mathematical Model for Predicting Capillary Pressure

Often difficulties and measurement uncertainties arise in determination of capillary pressure in laboratory experiments. In order to avoid this problem, we have developed a new mathematical model for calculating capillary pressure. The adequacy of fit for this model has been confirmed experimentally and by comparing with literature data. Based on the model, we propose a new and simpler method for calculating the relative permeability of rock.

Pore-scale investigation of some effective parameters on immiscible displacement efficiency using Free Energy model of Lattice Boltzmann method

The effects of capillary number, viscosity ratio, wettability and interfacial tension on immiscible displacement efficiency in porous media were numerically investigated. These parameters greatly affect the efficiency of flooding processes which are carried out in order to enhance oil recovery after the primary stage of oil production. Cahn-Hilliard type Free Energy model of Lattice Boltzmann method was used which we believe it is the first time use of this model to conduct such study. Constant velocity boundary condition was developed for this model to simulate injection of displacing liquid in different injection rates through heterogeneous porous medium. The model has been validated by three benchmark tests which confirm the ability of the model in simulating contact angles, velocity profile inside a pore and determination of capillary pressure. Our results show that areal sweep efficiency, ultimate recovery factor and breakthrough time improve with a decrease in capillary number by reducing injection rate. Decreasing viscosity ratio by increasing displacing phase viscosity shows improvement of flow stability and enhancement of displacement recovery. Wettability alteration from displaced-phase-wet to displacing-phase-wet, leads to remarkable increase of sweep efficiency and ultimate recovery. Finally, increasing interfacial tension slightly enhances displacement efficiency in forced imbibition process, when interfacial tension is high enough that miscibility does not occur between phases. Comparison of our results with previous experimental and numerical results in literature shows consistency in some cases and contradiction in others.

Characteristics, origin, and role of salt minerals in the process of hydrocarbon accumulation in the saline lacustrine basin of the Yingxi Area, Qaidam, China

In recent years, an important discovery in exploration has been made in $$ E_{3}^{2} $$ of Oligocene in the Yingxi Area of the Western Qaidam Basin. Based on core observation, systemic microscopic characteristics analysis, mineralogy analysis and geochemical analysis, the mineral characteristics, origin, and role in the process of hydrocarbon accumulation in Oligocene in the saline lacustrine basin are systemically investigated in the Yingxi Area of the Qaidam Basin: (1) In this area, there are four important salt minerals: halite, gypsum, glauberite and celestite, which form saline layers with a certain thickness or develop in matrix carbonate rock in the form of mineral particles. In the upper reservoir group in the middle of saline layers, the saline layers are thicker, mainly rock salt, where thin oil layers are developed. In lower reservoir groups, the saline layers are thinner, mainly gypsum. (2) Salt minerals possess geochemical characteristics of “low content of Mn”. The matrix carbonate rock associated with salt minerals has “low temperature” carbon and oxygen isotope geochemical characteristics, and petrological characteristics without the hydrothermal minerals and distribution characteristics with a very wide range. All the above characteristics demonstrate that the salt minerals in this area are a typical deposition type in the saline lacustrine basin, and not a hydrothermal brine precipitation type. (3) “Salt” plays a critical role in the process of hydrocarbon accumulation. Salt minerals play the roles of crack-filling and sealing to prevent dissipation of oil and gas. In addition, salt layers play the role of sealing and covering due to high capillary breakthrough pressure and plastic characteristics. Salt minerals promote secondary pore development in dolomite, and exhibit the negative effect of occupying certain reservoir space. The results of this research can provide important guidance for oil and gas exploration in subsalt layers of saline lacustrine carbonate rocks.

Wicking Tests for Unidirectional Fabrics: Measurements of Capillary Parameters to Evaluate Capillary Pressure in Liquid Composite Molding Processes.

During impregnation of a fibrous reinforcement in liquid composite molding (LCM) processes, capillary effects have to be understood in order to identify their influence on void formation in composite parts. Wicking in a fibrous medium described by the Washburn equation was considered equivalent to a flow under the effect of capillary pressure according to the Darcy law. Experimental tests for the characterization of wicking were conducted with both carbon and flax fiber reinforcement. Quasi-unidirectional fabrics were then tested by means of a tensiometer to determine the morphological and wetting parameters along the fiber direction. The procedure was shown to be promising when the morphology of the fabric is unchanged during capillary wicking. In the case of carbon fabrics, the capillary pressure can be calculated. Flax fibers are sensitive to moisture sorption and swell in water. This phenomenon has to be taken into account to assess the wetting parameters. In order to make fibers less sensitive to water sorption, a thermal treatment was carried out on flax reinforcements. This treatment enhances fiber morphological stability and prevents swelling in water. It was shown that treated fabrics have a linear wicking trend similar to those found in carbon fabrics, allowing for the determination of capillary pressure.

Development of a numerical workflow based on <i>μ</i>-CT imaging for the determination of capillary pressure–saturation-specific interfacial area relationship in 2-phase flow pore-scale porous-media systems: a case study on Heletz sandstone

Abstract. In this case study, we present the implementation of a finite element method (FEM)-based numerical pore-scale model that is able to track and quantify the propagating fluid–fluid interfacial area on highly complex micro-computed tomography (μ-CT)-obtained geometries. Special focus is drawn to the relationship between reservoir-specific capillary pressure (pc), wetting phase saturation (Sw) and interfacial area (awn). The basis of this approach is high-resolution μ-CT images representing the geometrical characteristics of a georeservoir sample. The successfully validated 2-phase flow model is based on the Navier–Stokes equations, including the surface tension force, in order to consider capillary effects for the computation of flow and the phase-field method for the emulation of a sharp fluid–fluid interface. In combination with specialized software packages, a complex high-resolution modelling domain can be obtained. A numerical workflow based on representative elementary volume (REV)-scale pore-size distributions is introduced. This workflow aims at the successive modification of model and model set-up for simulating, such as a type of 2-phase problem on asymmetric μ-CT-based model domains. The geometrical complexity is gradually increased, starting from idealized pore geometries until complex μ-CT-based pore network domains, whereas all domains represent geostatistics of the REV-scale core sample pore-size distribution. Finally, the model can be applied to a complex μ-CT-based model domain and the pc–Sw–awn relationship can be computed.

A laboratory study on capillary sealing efficiency of Iranian shale and anhydrite caprocks

Abstract Caprock has the most important role in the long term safety of formation gas storage. The caprocks trap fluid accumulated beneath, contribute to lateral migration of this fluid and impede its upward migration. The rapid upward passage of invasive plumes due to buoyancy pressure is prevented by capillary pressure within these seal rocks. In the present study, two main seal rocks, from the Zagros basin in the southwest of Iran, a shale core sample of Asmari formation and an anhydrite core sample of Gachsaran formation, were provided. Absolute permeabilities of shale and anhydrite cores, considering the Klinkenberg effect, were measured as 6.09 × 10 −18 and 0.89 × 10 −18 m 2 , respectively. Capillary sealing efficiency of the cores was investigated using gas breakthrough experiments. To do so, two distinct techniques including step by step and residual capillary pressure approaches were performed, using carbon dioxide, nitrogen and methane gases at temperatures of 70 and 90 °C, under confining pressures in the range 24.13–37.92 MPa. In the first technique, it was found that capillary breakthrough pressure of the cores varies in the range from 2.76 to 34.34 MPa. Moreover, the measurements indicated that after capillary breakthrough, gas effective permeabilities lie in range 1.85 × 10 −21 – 1.66 × 10 −19 m 2 . In the second technique, the minimum capillary displacement pressure of shale varied from 0.66 to 1.45 MPa with the maximum effective permeability around 7.76 × 10 −21 – 6.69 × 10 −20 m 2 . The results indicate that anhydrite caprock of the Gachsaran formation provides proper capillary sealing efficacy, suitable for long term storage of the injected CO 2 plumes, due to its higher capillary breakthrough pressure and lower gas effective permeability.

Parametric analysis of caprock integrity in relation with CO2 geosequestration: capillary breakthrough pressure of caprock and gas effective permeability

AbstractCaprock integrity is a primary criterion for evaluating depleted oil and gas reservoirs for long‐term safety of carbon dioxide geosequestration. The occurrence of capillary leakage is inevitable in caprock. This phenomenon occurs whenever the buoyancy pressure due to accumulated CO2 plumes dominates the capillary pressure of caprock, and thereby the plumes intrude into the pore throats. In this study, experimental investigation of the effective parameters, including overburden pressure, ambient temperature, and CO2 impurities in the form of non‐condensable and non‐reactive CH4 and N2 gases on the capability of shale and anhydrite cores to preserve CO2 gas is conducted. In this regard, capillary breakthrough pressure and CO2 gas effective permeability analysis were performed applying two distinct techniques, step by step and residual capillary pressure. Experiments were conducted at the temperatures of 35, 70, and 90 °C and overburden pressures in the range of 3500–5800 psi. Two main seal rocks, including shale and anhydrite core samples, from middle Asmari and Gachsaran formations of the Zagros Basin located in the southwest of Iran were used. Regarding the high capillary breakthrough pressure and low gas effective permeability after outbreak of the leakage, all three parameters have noticeable effects on capillary sealing efficiency of the caprocks. The results indicate that impurities such as CH4 and N2 have a significant effect on capillary breakthrough pressure of caprock and gas effective permeability. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

Simultaneous determination of capillary pressure and relative permeability curves from core-flooding experiments with various fluid pairs

[1] Capillary pressure and relative permeability drainage curves are simultaneously measured on a single Berea Sandstone core by using three different fluid pairs, namely gCO 2/water, gN2/water and scCO 2/brine. This novel technique possesses many of the characteristics of a conventional steady-state relative permeability experiment and consists of injecting the nonwetting fluid at increasingly higher flow rates in a core that is initially saturated with the wetting phase, while observing fluid saturations with a medical x-ray CT scanner. Injection flow rates (0.5–75 mL/min) are varied so as to generate a large range of capillary pressures (up to 18 kPa), whereas fluid-pairs and experimental conditions are selected in order to move across a range interfacial tension values ( γ12=40−65 mN/m), while maintaining a constant viscosity ratio ( μw/μnw ≈30). Moreover, these experiments, carried out at moderate pressures ( P=2.4 MPa and T=50°C), can be compared directly with results for gas/liquid pairs reported in the literature and they set the benchmark for the experiment at a higher pressure ( P=9 MPa and T=50°C), where CO 2 is in the supercritical state. Contrary to some prior investigations, from these experiments we find no evidence that the scCO 2/brine system behaves differently than any of these other fluid pairs. At the same time, capillary pressure data show a significant (but consistent) effect of the different values for the interfacial tension. The fact that the three different fluid pairs yield the same drainage relative permeability curve is consistent with observations in the petroleum literature. Additionally, the observed end-point values for the relative permeability to the nonwetting phase ( kr,nw ≈0.9) and the corresponding irreducible water saturations ( Sw,irr ≈0.35) suggest that water-wet conditions are maintained in each experiment. The reliability of the measured relative permeability curves is supported by the very good agreement with data from the literature obtained on Berea Sandstone cores and with various gas/liquid pairs. The Brooks-Corey model is used to describe the capillary pressure data and the parameters derived from these matches provide a fair prediction of the relative permeability curves. It is shown that the apparent low end-point relative permeabilities to the nonwetting phase reported in previous experimental studies are caused by the low viscosity of CO 2 relative to water, rather than by the rock heterogeneity. In fact, the former controls the level of capillary pressure that can be achieved experimentally, thus restricting the applicability of some of the conventional methods to measure relative permeability curves for gas/liquid systems.

Pore-lining phases and capillary breakthrough pressure of mudstone caprocks: Sealing efficiency of geologic CO2 storage sites

Subsurface containment of CO2 requires an effective caprock seal. Many previous studies on seals have relied on macroscopic measurements of capillary breakthrough pressure and other petrophysical properties without direct examination of solid phases that line pore networks and contact fluids. However, pore-lining phases strongly contribute to sealing behavior through interfacial interactions among CO2, brine, and the mineral or non-mineral phases. We examined continental and marine mudstones using high resolution (i.e., sub-micron), direct observations of pore-lining phases and X-ray diffraction (XRD). Our results indicate that sealing efficiency (i.e., breakthrough pressure) is governed by pore shapes and pore-lining phases that are not identifiable except through direct characterization of pores. Bulk XRD data do not indicate which phases line the pores and may be especially lacking for mudstones with organic material. Organics can line pores and may represent once-mobile organics that modified wettability of an originally clay-lined pore network. For shallow formations (i.e., <800m depth), interfacial tension and contact angles result in breakthrough pressures that may be as high as those needed to fracture the rock—thus, in the absence of fractures, high capillary sealing efficiency is indicated. Deeper seals have poorer capillary sealing if some reduction in water-wetting occurs, with an increase in pressure and temperature, on minerals and/or pore-lining organic phases.