Browsing by Subject "Capillary pressure"
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Item Capillary pressure curve and liquid permeability estimation in tight oil reservoirs using pressure decline versus time data(2018-12-07) Ozowe, Williams Osagie; Sharma, Mukul M.Estimating oil recovery from shale is a difficult process because organic mudrocks have very low permeability (10nD - 100nD), high kerogen and clay content, a complex pore structure and low porosity (typically less than 10%). In addition, most of the pore sizes in organic mudrocks are within the nanometer range, thus making the process of oil intrusion very difficult to achieve and even harder to measure with certainty. Several methods have been proposed to estimate saturation profiles and capillary pressure curves in conventional rocks, but these methods fail in tight rocks because of the complexities inherent in these types of reservoirs. This report presents a new method that makes use of the pressure decline versus time data to estimate the capillary pressure drainage curve in tight rocks. The method was used to estimate the capillary drainage curve for an Eagle Ford shale and it was also used to determine the shale's liquid permeability using the early time data of the pressure decline curve. The data obtained during the experiment could be used to estimate fluid saturations as a function of time which can be very useful in determining relative permeability curves in the shale. This new procedure is easy, fast and can be reversed to estimate imbibition curves as well. It can be applied to both conventional and unconventional rocks and it can be useful in EOR experiments to estimate oil recovery as a function of time. Furthermore, this report presents the use of NMR as a useful tool in examining fluid distributions and characterizing fluid types within tight rocks, via a combination of NMR T₁ and T₂ dataItem Compositional three-phase relative permeability and capillary pressure models using Gibbs free energy(2016-08) Sadeghi Neshat, Sajjad; Pope, G. A.; Ezekoye, Ofodike E.; Lake, LarryBoth relative permeability and capillary pressure depend on composition as well as saturation, but classical models neglect this dependence. The objective of this research was to develop coupled three-phase relative permeability and capillary pressure models for implementation in a four-phase flow compositional equation-of-state simulator. The models applied to several complex but practical reservoir simulation problems. Models independent of phase label have many advantages in terms of both numerical stability and physical consistency. Identification of hydrocarbon and aqueous phases based on their molar Gibbs Free Energy (GFE) is a key feature of the new model. Instead of using labels (gas/oil/2nd liquid/aqueous) to define permeability parameters such as end points, residual saturation and exponents, the parameters are continuously interpolated between reference values using the Gibbs free energy of each phase at each time step. Consequently, the formulation used to implement other relevant physical parameters must be consistent with the new approach. A comprehensive but simple vii algorithm was developed for this purpose. The algorithm allows for very general threephase hysteresis in both relative permeability and capillary pressure. An important part of this thesis is analyzing the results of a recent series of experiments on the effect composition on relative permeability. These new data were used to calibrate the new GFE relative permeability model and apply it in a compositional reservoir simulator. The robustness of the new GFE model was shown through complex simulations such as solvent flooding, miscible/immiscible WAG processes, well stimulation processes using solvents to remove condensate and/or water blocks in both conventional and unconventional formations and other challenging applications involving both mass transfer between phases and phase changes. The interpolation of relative permeability parameters based on GFE instead of phase labels completely solves the discontinuity problem caused by phase flipping or misidentification. Therefore, simulations run significantly faster and are physically correct. The novelty of this research is in integrating and unifying relevant physical parameters including trapping number, hysteresis and capillary pressure into one rigorous algorithm with compositional consistency and in the development and application of a practical procedure for numerical compositional reservoir simulations.Item Dynamic petrophysical properties of laminated rocks : an experimental investigation(2018-12-07) Alrubaie, Naif Mohammed; Torres-Verdín, Carlos; Heidari, ZoyaLaminae included in rock samples are small-scale heterogeneities that introduce anisotropy to the larger-scale rock system. They can be described in terms of grain size variations, as in a clastic sediment that is interbedded with shale layers. Such variations in grain size translate into variations in pore and pore-throat size distributions, and they control the effective two-phase fluid transport properties of the rock. Ultimately, they impact hydrocarbon recovery. This thesis implements an experimental workflow to study and quantify the impact of laminations on dynamic petrophysical properties in the presence of two distinct types of layering: cross and parallel. Accordingly, relative permeability and capillary pressure are measured under two flow conditions: across (perpendicular flow) and along layers (parallel flow). Two cylindrical composite rock samples were fabricated in which the first composite sample was interbedded with a lower permeability rock (Berea sandstone interbedded with Kentucky sandstone), and the second one was interbedded with a higher permeability rock (Kentucky sandstone interbedded with Berea sandstone) to represent the layering cases defined above. Multiple laboratory experiments were carried out to measure mercury intrusion capillary pressure (MICP) and saturation-dependent relative permeability. These measurements were complemented with micro-computed tomography images and nuclear magnetic resonance (NMR) measurements. For the perpendicular flow experiments, I sealed the sub-samples into a cylindrical sample in order to allow mercury to flow across them. The seal surrounds the samples and forces mercury to intrude only through the two ends (faces) of the composite samples. In the parallel flow experiments, I first sealed each piece individually and then sealed the entire stack. This was done to ensure that flow pathways between the pieces were sealed. A bimodal pore-size distribution in the Berea interbedded with Kentucky and in the Kentucky interbedded with Berea samples was revealed by MICP measurements in the parallel layering composite cores. In the cross-layering experiments, I observed a bimodal pore-size distribution for the two rock arrangements. Relative permeability was higher in the parallel flow composite cores compared to the perpendicular flow composite cores. In core data analysis, samples are taken from intervals considered representative of one single rock type. When the data are quality checked, petrophysical measurements from samples that exhibit grain laminations are often excluded. This bias propagates to simulation work and leads to results that often do not match field data.Item The Effects of Capillary Pressure on Displacements in Stratified Porous Media(1980-12) Yokoyama, Yoshio; Lake, Larry W.The purpose of this study is to obtain a better understanding of capillary pressure effects on fluid dis-placement in stratified porous media. We do this by pre-senting and validating dimensionless scaling parameters which will assist in the evaluation of these effects. The interpretation of flow perpendicular to strati-fied layers is important because it is one of the greatest causes of mixing, thus, determining the longitudinal satura-tion profile. In stratified layers with large permeability contrast, the transverse flow (crossflow) due to capillary imbibition retards the fronts in higher permeability layers and advances the fronts in lower permeability layers. Conse-quently greater oil recovery results when compared to a no-crossflow case. In this study, emphasis was placed on the analysis of transverse capillary crossflow effects. First, a semi-implicit two-phase, two-dimensional, incompressible fluid simulation model is developed by a finite difference method. A three-point weighting scheme is incorporated to reduce numerical dispersion (truncation error) in a routine of inter-block transmissibility evaluation. Next five dimensionless parameters are introduced to correlate the porous medium's heterogeneity with mixing caused by capillary crossflow. Those are the dimensionless time (t0), the transverse capillary number (NCT), the longi-tudinal capillary number (NCL) , the heterogeneity function (R¢K) and the Leverett j-function. Finally the dimensional analysis is verified through computer simulation of two-layered porous media models, and several dimensionless correlation graphs are drawn. The study provides a basis for analyzing displace-ment behavior in stratified media and also suggests the same analysis can be extended to more complicated media.Item Estimating capillary pressure from NMR measurements using a pore-size-dependent fluid substitution method(2019-05) Wang, You; Torres-Verdín, Carlos; Heidari, ZoyaThis report introduces a workflow to calculate capillary pressure curves from NMR transverse relaxation time ( T₂ ) distributions of partially hydrocarbon-saturated measurements. First, a pore-size-dependent fluid-substitution (PSDFS) joint inversion method is developed to correct T₂ distributions for hydrocarbon effects in partially hydrocarbon-saturated rocks. A PSDFS joint inversion on the T₂ distributions of samples at different hydrocarbon saturations is used to estimate input parameters for fluid substitution and to reconstruct the fully water-saturated T₂ distribution. Next, the T₂ distribution of the fully water saturated sample is converted to a pore-size distribution using an estimated surface relaxivity. Finally, assuming a linear relationship between pore and throat size distributions, the saturation-dependent capillary pressure curve can be estimated using a triangular tube model. The PSDFS joint inversion is validated on NMR measurements of Berea sandstone samples with different values of hydrocarbon saturation. The feasibility of our joint inversion method is confirmed by comparing the calculated fully water-saturated T₂ distribution to the T₂ distribution of the measured fully water-saturated rock sample. The capillary pressure curves are derived from fluid-substituted fully water-saturated T₂ distributions and compared to mercury injection capillary pressure (MICP) measurements. Capillary pressure curves derived with the PSDFS method agree well with MICP measurementsItem Evaluation of lean and rich gas injection for improved oil recovery in hydraulically fractured reservoirs(2021-05-05) Ozowe, Williams Osagie; Sharma, Mukul M.; Lake, Larry; Daigle, Hugh; Okuno, Ryosuke; Gao, BoEstimating improvements in oil recovery in shales can be difficult, because of their ultra-low permeability - often in the nanodarcy range. In addition, poroelastic changes occurring within the reservoir during production, have a direct impact on porosity and flow paths. Recovery estimates from simulations are imprecise, because inaccurate capillary pressure curves and liquid permeability estimates are often used for forecasting. This work presents a new method to measure liquid saturation and capillary pressure in shales, by integrating the time-dependent pressure drop data observed within the bulk liquid phase, when a shale sample is under liquid pressure. This work also presents an experimental method to estimate liquid permeability in shale, by using the early time portion of the liquid pressure decay data - that has been corrected for temperature effects – to estimate diffusivity, via a graphical approach that approximates the solution of the radial diffusivity equation coupled with the mass balance equation. In unconventional reservoirs it is quite common to experience a rapid decline in production and reservoir pressure during primary production. For this reason, operators have sought to find ways to improve oil recovery via cyclic gas injection in shale reservoirs. To achieve this, it is important to understand the role of fluid compressibility, miscibility, soak time and injection pressure on oil recovery. The choice of these parameters can have a significant impact on recovery factor, the produced gas-oil ratio and economic viability. This work presents results from an experimental study of these properties on Eagle Ford core plugs and crushed samples, via the injection of liquid and gaseous recovery agents at room temperature. Results show that gaseous solvents perform better than liquid solvents and oil recovery increases with injection pressure, and with increasing surface area to volume ratio of the shale samples. To better understand the role of poroelastic changes on oil recovery, cyclic gas injection simulations were conducted in the Eagle Ford shale using a fully coupled compositional, geomechanical hydraulic fracturing and reservoir simulator. Results obtained show that effective stress changes occurring during injection and production cycles in the stimulated reservoir volume results in a decrease in reservoir permeability, and this reduces oil recovery. Also, simulation results between miscible and immiscible gases show that immiscible gases yield lower oil recovery factors and higher gas-oil ratios, than more miscible gases. Finally, from simulation studies carried out for the Bakken and Wolfcamp shales, it was observed that increasing the mole fraction of the heavier molecular weight hydrocarbon gases in the injection gas improves miscibility with the reservoir fluid, and increases oil recovery. Additional results show that this enhanced degree of miscibility of the injection gas with the reservoir fluid, was not impacted by the substitution of low molecular weight hydrocarbons for carbon dioxide in a hybrid injection gas mixture.Item Local capillary trapping in geological carbon storage(2012-08) Saadatpoor, Ehsan, 1982-; Bryant, Steven L.; Sepehrnoori, Kamy, 1951-After the injection of CO₂ into a subsurface formation, various storage mechanisms help immobilize the CO₂. Injection strategies that promote the buoyant movement of CO₂ during the post-injection period can increase immobilization by the mechanisms of dissolution and residual phase trapping. In this work, we argue that the heterogeneity intrinsic to sedimentary rocks gives rise to another category of trapping, which we call local capillary trapping. In a heterogeneous storage formation where capillary entry pressure of the rock is correlated with other petrophysical properties, numerous local capillary barriers exist and can trap rising CO₂ below them. The size of barriers depends on the correlation length, i.e., the characteristic size of regions having similar values of capillary entry pressure. This dissertation evaluates the dynamics of the local capillary trapping and its effectiveness to add an element of increased capacity and containment security in carbon storage in heterogeneous permeable media. The overall objective is to obtain the rigorous assessment of the amount and extent of local capillary trapping expected to occur in typical storage formations. A series of detailed numerical simulations are used to quantify the amount of local capillary trapping and to study the effect of local capillary barriers on CO₂ leakage from the storage formation. Also, a research code is developed for finding clusters of local capillary trapping from capillary entry pressure field based on the assumption that in post-injection period the viscous forces are negligible and the process is governed solely by capillary forces. The code is used to make a quantitative assessment of an upper bound for local capillary trapping capacity in heterogeneous domains using the geologic data, which is especially useful for field projects since it is very fast compared to flow simulation. The results show that capillary heterogeneity decreases the threshold capacity for non-leakable storage of CO₂. However, in cases where the injected volume is more than threshold capacity, capillary heterogeneity adds an element of security to the structural seal, regardless of how CO₂ is accumulated under the seal, either by injection or by buoyancy. In other words, ignoring heterogeneity gives the worst-case estimate of the risk. Nevertheless, during a potential leakage through failed seals, a range of CO₂ leakage amounts may occur depending on heterogeneity and the location of the leak. In geologic CO₂ storage in typical saline aquifers, the local capillary trapping can result in large volumes that are sufficiently trapped and immobilized. In fact, this behavior has significant implications for estimates of permanence of storage, for assessments of leakage rates, and for predicting ultimate consequences of leakage.Item Phase behavior and compositional simulation of solvent EOR processes in unconventional reservoirs(2020-08-10) Sadeghi Neshat, Sajjad; Pope, G. A.; Bahadur, Vaibhav; Okuno, Ryosuke, 1974-; Bogard, David; Chen, DongmeiRecent advances in hydraulic fracturing and horizontal drilling technologies applied to unconventional resources have enabled very large increases in oil and gas production in the United States. While the initial production rate from new wells is often high, the rate of decline during the first year of production is also very high. The ultimate hydrocarbon recovery using current technology is estimated to be between 5 to 10%, which is very low compared to conventional oil reservoirs. These challenges have increased the demand for enhanced oil recovery (EOR) in unconventional reservoirs. Unconventional reservoirs have very different properties than conventional reservoirs such as extremely low permeability, wide and complex pore size distributions, high total organic carbon (TOC), and high heterogeneity. New cost effective EOR methods consistent with these properties are needed. This research presents a new framework for phase behavior modeling and compositional simulation of solvent EOR in unconventional reservoirs (also called tight oil reservoirs). Several new physical models were developed for this purpose. The new developments include a three-phase capillary pressure model, a phase stability method for multi-component mixtures with capillary pressure, coupled three-phase flash and capillary pressure models, and a new oil characterization method for organic-rich reservoirs. These models improve petrophysical, thermodynamic, and transport modeling of unconventional reservoirs. All new models were implemented in UTCOMP, an equation-of-state compositional reservoir simulator. The simulator was used for design and optimization of solvent EOR processes in organic-rich tight oil reservoirs. The oil recovery using cyclic huff-n-puff injection of a variety of solvents such as natural gas, CO₂, methanol and dimethyl ether (DME) was compared. DME has the best performance among all solvents considered in this research. At reservoir conditions, DME mixes with both water and hydrocarbon phases. This helps to remove water blockage as well as retrograde condensate in gas-condensate reservoirs. DME can also extract part of the bitumen in the rock, which does not flow by itself due to its extremely high viscosity. Since the recovery rate of DME is very high, it can be recycled and injected back into the reservoir to reduce its net cost.Item Phase stability analysis for tight porous media with the Helmholtz free energy(2020-03-27) Achour, Sofiane Haythem; Okuno, Ryosuke, 1974-Phase stability analysis is commonly used to determine whether a mixture splits into two or more phases at equilibrium. Compositional reservoir simulators use it to initiate phase equilibrium calculations which are necessary to evaluate the amount of oil and gas present in a reservoir. However, conventional methods for stability analysis are not robust when applied to modeling phase behavior in tight reservoirs where equilibrium phase pressures can be different. Capillary forces in tight reservoirs are strong enough to alter the equilibrium phase compositions and pressures. Phase stability analysis in tight porous media is challenging because it involves predicting the appearance of an additional phase, the pressure of which is initially unknown. This causes common failures of conventional stability analysis algorithms based on the Gibbs free energy. Due to the lack of robust algorithms, the effects of capillary forces on phase behavior have not yet been included in any commercial software. This is a substantial problem that makes it difficult to accurately model and optimize the production of hydrocarbons from tight reservoirs. This report presents a new method of phase stability prediction for multicomponent mixtures in tight formation based on the minimization of the Helmholtz free energy. Case studies demonstrate why conventional methods based on the Gibbs free energy are not robust in the presence of capillary pressure. The new method can correctly identify the pressure-temperature region for a given mixture, outside of which the mixture is stable for any capillary pressureItem Scale effects on the latent heat of phase change & the effect of dynamic contact angles on dynamic capillary pressure(2014-12) Shin, Jeong-Heon; Deinert, Mark; Shi, Li; DiCarlo, David; Halil Berberoglu; Bogard, David G.Surface tension is an important material property that affects the behavior of micro/nano size thermal-fluid systems. In this dissertation, I investigate how surface tension affects the latent heat of a phase change in nanoscale systems as well as on the movement of water in microstructures. Classical thermodynamic models were developed to describe how the latent heat of melting in nano-pores depends on scale and were extended to the melting of metallic nano-particles. The results from these models were verified by comparison with experimental data from the open literature for hydrocarbons and water in nano-size pores, as well as for free standing metallic nano particles. A classical thermodynamic model was also developed to describe how the latent heat of vaporization depends on scale. This was verified experimentally using a Thermogravimetric Analysis/Differential Scanning Calorimeter available in the core facilities of the Texas Materials Institute. This verified that the latent heat of vaporization for water confined nano-pores decreases with pore size. A model for dynamic capillary pressure in porous media was analyzed using experimentally derived data for the velocity dependent contact angle of water on SiO₂ glass. The data were derived from images of microfluidic flows in capillary tubes, obtained using high speed digital microscopy.Item Under-pressure in the Bravo Dome natural CO₂ field and its implications for geological CO₂ storage (GCS)(2018-05) Akhbari, Daria; Hesse, Marc; Breecker, Daniel; Flemings, Peter; Larson, Toti; DiCarlo, DavidGeological carbon storage (GCS) has the potential to reduce anthropogenic CO₂ emissions, if large volumes can be injected. Storage capacity is limited by regional pressure build-up in the subsurface. However, natural CO₂ reservoirs are commonly under-pressured, suggesting that natural processes counteract the pressure build-up and increase storage security. To identifythese processes, I studied Bravo Dome natural CO₂ reservoir, where the gas pressure are significantly below hydrostatic pressure. Here, I showed that the dissolution of CO₂ into the brine contributes to observed under-pressure conditions because Bravo Dome appears to be isolated from the ambient hydrologic system. This study indicated that the pressure drop in the gas due to CO₂ dissolution slows down convective dissolution dramatically. I present 2D numerical simulations and reproduce the observed reservoir pressures and noble gas compositions. Based on this study, CO₂ at Bravo Dome must at least persist for 300 ka to produce the observed noble gas composition and reservoir pressures. Lastly, I showed that compartmental gas pressure observed at Bravo Dome are controlled by capillary forces.