Browsing by Subject "Permeability"

Now showing 1 - 20 of 67

Analysis of Areal Permeability Variations - San Andres Formation (Guadalupian): Algerita Escarpment, Otero County, New Mexico
(1988-08) Kittridge, Mark Gerard; Lake, Larry W.
This paper presents the results of an integrated outcrop and subsurface characterization study conducted on the San Andres Formation of the Permian basin. More than 1600 permeability measurements were obtained from an outcrop section located along the Algerita Escarpment in southeastern New Mexico using an experimental mechanical field permeameter (MFP). Subsurface core data (permeability and porosity) were available from ten closely spaced wells in the Wasson field on the adjacent Northwest Shelf of the Permian basin. Standard population statistics, contour plots and vertical profiles, and geostatistical techniques were used in an attempt to characterize the extremely heterogeneous formation. The outcrop permeability data were found to be log-normally to power-normally distributed, with 12 of 16 data sets having a negative p value. Mean permeability and variance was lowest in the fusulinid dolowackestones, while the highest mean was found in the dolopackstones and dolograinstone intervals. Permeability contour maps of the outcrop grid data typically revealed isolated 'pods' of high permeability in a generally low permeability matrix. The vertical transect measured displayed rapidly varying permeability, with values changing over a very short interval. Geostatistical analysis with the variogram predicted three distinct correlation lengths: 40 feet, 3 to 5 feet, and approximtely 0.25 feet, depending on the spacing of the data used. Predicted correlation length decreased with a decrease in sample spacing. The correlation length was found to be invariant with respect to direction, indicating that the formation is isotropic. Subsurface permeability and porosity data were analyzed in a similar manner. The permeability data was found to be log-normally distributed while the porosity data was power normal. The associated variance on the core plug data was much larger than on the whole core data. Vertical permeability and porosity profiles were similar to that observed from the outcrop vertical transect: alternating high and low values occurring over a very short distance. Variograms indicated a correlation length of approximtely 10.0 feet (vertically) for both permeability and porosity.
Analytic Methods to Calculate an Effective Permeability Tensor and Effective Relative Permeabilities for Cross-Bedded Flow Units
(1990-05) Kasap, Ekrem; Lake, Larry W.
Most naturally-occurring permeable media are heterogeneous on too small of a scale to include all the detailed heterogeneity into a numerical simulation. Instead, lumping the effects of those' heterogeneities in a form that can be easily inserted into simulators is an alternative. Many of the effects of those heterogeneities can be quantified analytically by calculating an effective permeability tensor, with non-zero off-diagonal terms, when the heterogeneity is non-uniform. If there exist some prototype regularities, in addition to the effective permeability tensor, effective relative permeabilities can be generated to account for an uneven displacement front in the direction normal to the main flow in viscously dominated flows. For non-uniform heterogeneities, an analytic method to calculate effective cell permeabilities as a tensor based on geometry, size of the numerical cell, tensorial local permeabilities and geology within the cell is proposed. The method is based on flow through parallel and serial cross-beds which is subsequently rotated to arrive at tensorial permeabilities having non-zero off-diagonal terms. The procedure is applied to a simulation of flow through an outcrop of the eolian Page Sandstone. The results of the fluid flow simulations show that the relative positions of the main geologic features and the ratio between the grainflow and windripple permeabilities are more important than bounding surfaces, cross-bedding and dispersion in determining flow behavior. For uniform heterogeneities, an analytical method to generate effective relative permeabilities which account for an uneven displacement front is proposed. The procedure considers only viscously-dominated flows and consists of discretizing the flow unit into subunits and homogenizing each subunit by calculating an effective permeability tensor which resolves cross-bedding and cross-bed orientation. Effective relative permeabilities are then generated analytically to account for differences in sweep between the subunits. · The method is applied to one-dimensional simulations of fluid flow in the C2 and B units of the Page Sandstone with less detail (36 elements, instead of 11520 elements of the detailed simulations). The resulting recovery predictions for different mobility ratios are compared with the ones from the detailed simulations. The comparisons of the recovery predictions indicate that the calculated effective relative permeabilities can capture the effect of heterogeneity on the sweep efficiency. Both methods have been validated using a finite element numerical simulator which models the permeability discontinuities explicitly. Comparison of analytical and numerical effective permeability and effective relative permeabilities indicate that the analytically calculated effective permeabilities and generated effective relative permeabilities are valid, easy to implement, and are practical alternatives to account for detailed heterogeneities in numerical simulations
Centrifuge measurement of two-phase transient flow in rigid porous media
(2016-08) Blake, Calvin Russell; Zornberg, Jorge G.; Mohanty, Kishore K
Gravity driven multi-phase flow in porous media is an important mode of fluid transport in several geologic settings. Some applications where gravity drainage may play an important role in the movement of a fluid can include primary oil recovery from a petroleum reservoir or water flow into the ground surface. Because of the similarities between a single-gravity environment and a centrifugal environment, measurements of two-phase flow are often conducted in the centrifuge to observe the behavior of the whole system under gravity-like conditions while reducing the time of measurement. In this study, measurements of transient fluid outflow from sandstone cores were conducted in the centrifuge using air as the invading phase. The draining phase in these experiments comprised three different brines and a light mineral oil. Hydraulic conductivity functions and capillary pressure curves were determined from this data using a numerical history matching technique, and the results were compared with two prevailing analytical models. The results of this study corroborate previous findings that a full numerical history match can easily predict more realistic hydraulic conductivity functions than the prevailing analytical models.
Characterization of petrophysical properties of organic-rich shales by experiments, lab measurements and machine learning analysis
(2018-12-03) Jiang, Han, Ph. D.; Daigle, Hugh; Sharma, Mukul; Prodanović, Maša; Heidari, Zoya; Javadpour, Farzam
The increasing significance of shale plays leads to the need for deeper understanding of shale behavior. Laboratory characterization of petrophysical properties is an important part of shale resource evaluation. The characterization, however, remains challenging due to the complicated nature of shale. This work aims at better characterization of shale using experiments, lab measurements, and machine leaning analysis. During hydraulic fracturing, besides tensile failure, the adjacent shale matrix is subjected to massive shear deformation. The interaction of shale pore system and shear deformation, and impacts on production remains unknown. This work investigates the response of shale nanoscale pore system to shear deformation using gas sorption and scanning electron microscope (SEM) imaging. Shale samples are deformed by confined compressive strength tests. After failure, fractures in nanoscale are observed to follow coarser grain boundaries and laminae of OM and matrix materials. Most samples display increases in pore structural parameters. Results suggest that the hydrocarbon mobility may be enhanced by the interaction of the OM laminae and the shear fracturing. Past studied show that the evolution of pore structure of shale is associated with thermal maturation. However, the evolution of shale transport propreties related to thermal maturation is unclear due to the difficulty of conducting permeability measurement for shale.This work studies evolution of permeability and pore structure measurements using heat treatment. Samples are heated from 110°C to 650°C. Gas sorption and GRI (Gas Research Institute) permeability measurements are performed. Results show that those petrophysical parameters, especially permeability, are sensitive to drying temperature. Multiscale pore network features of shale are also revealed in this study. Characterizing fluids in shale using nuclear magnetic resonance (NMR) T₁-T₂ maps is often done manually, which is difficult and subjected to human decisions. This work proposes a new approach based on Gaussian mixture model (GMM) clustering analysis. Six clustering algorithms are performed on T₁1-T₂ maps. To select the optimal cluster number and best algorithm, two cluster validity indices are proposed. Results validate the two indices, and GMM is found to be the best algorithm. A general fluid partition pattern is obtained by GMM, which is less sensitive to rock lithology. In addition, the clustering performance can be enhanced by drying the sample
Cleanup of internal filter cake during flowback
(2005) Suri, Ajay; Sharma, Mukul M.
The flow initiation pressure (FIP) is used as an estimate of the differential pressure (between the reservoir and the well) required to initiate production. The standard practice to measure FIP uses a constant flowback rate. This method is shown to be inadequate to measure the FIP. An improved flowback method, which uses a series of constant differential pressures, is used instead to measure the FIP. This method closely represents the constant drawdown experienced between the reservoir and the wellbore. In addition the permeability during flowback is measured at increasing differential pressures, resulting in a spectrum of return permeability values. Two types of drilling fluids (sized calcium carbonate and bentonite) are used for conducting the filtration and flowback experiments for porous media ranging in permeability from 4 to 1500 md. Both single-phase and two-phase experiments are conducted in lab-simulated open-hole and perforated completions to better understand the factors affecting the FIP and the return permeability spectra. vii We observe small values for FIP in all the experiments (considerably smaller than those measured using the constant flowback method). The values of FIP yield pressure gradients that are achievable in vertical wells but may not be easily achieved in horizontal wells. The FIP and the return permeability spectra are controlled by the cleanup of the internal filter cake. A Bingham fluid in a network of pores is used to model the cleanup of the internal filter cake during flowback. The results indicate that very large pressure gradients are required during flowback to cleanup the entire internal filter cake. However, a pressure gradient of 10 psi / inch is found to yield a skin factor < 1 for most open-hole completions. For perforated completions, pressure gradients up to 20 psi / inch and flow rates up to 0.3 bbl/day/perf yield skin factors < 2.
Cluster Analysis in Reservoir Characterization
(1994-08) Muneta, Yasuhiro; Lake, Larry W.
Any raw data sampled in an oil field has a certain amount of noise; the sample may be called an obscure image of the real thing. We may eliminate the noise by a process of "image enhancement" in "statistical pattern recognition." Image enhancement is one of the important steps in processing large data sets to make them more suitable for classification than were the original data. In this work, cluster analysis, which is a method of image enhancement, is applied to some reservoir characterization problems such as permeability distributions of core samples, sand/shale sequences observed in wells, and pressure distributions in heterogeneous porous media to classify the sample data and find the intrinsic patterns (averaged images) from the original data sets. Cluster analysis is a multivariate statistical method. It is very general and can be applied to a wide area of scientific investigations. It is often called a tool of discovery or an unsupervised approach which doesn't depend on a priori information. It searches unknown-significant categories (patterns) themselves. Once we obtain typical patterns, we may analogously approach the real thing based on them. We find that cluster analysis is applicable to finding appropriate parent populations of a permeability distribution, theoretical indicator variograms of sand/shale sequences, and trends of effective permeability distribution.
Complexity in river-groundwater exchange due to permeability heterogeneity, in-stream flow obstacles, and river stage fluctuations
(2011-05) Sawyer, Audrey Hucks; Cardenas, Meinhard Bayani, 1977-; Catania, Ginny; Hodges, Ben; Mohrig, David; Reible, Danny
River-groundwater exchange (hyporheic exchange) influences temperature, water chemistry, and ecology within rivers and alluvial aquifers. Rates and patterns of hyporheic exchange depend on riverbed permeability, pressure gradients created by current-obstacle interactions, and river stage fluctuations. I demonstrate the response of hyporheic exchange to three examples of these driving forces: fine-scale permeability structure in cross-bedded sediment, current interactions with large woody debris (LWD), and anthropogenic river stage fluctuations downstream of dams. Using numerical simulations, I show that cross-bedded permeability structure increases hyporheic path lengths and modifies solute residence times in bedforms. The tails of residence time distributions conform to a power law in both cross-bedded and internally homogeneous riverbed sediment. Current-bedform interactions are responsible for the decade-scale tails, rather than permeability heterogeneity. Like bedforms, wood debris interacts with currents and drives hyporheic exchange. Laboratory flume experiments and numerical simulations demonstrate that the amplitude of the pressure wave (and thus hyporheic exchange) due to a channel-spanning log increases with channel Froude number and blockage ratio (log diameter : flow depth). Upstream from LWD, downwelling water transports the river’s diel thermal signal deep into the sediment. Downstream, upwelling water forms a wedge of buffered temperatures. Hyporheic exchange associated with LWD does not significantly impact diel surface water temperatures. I tested these fluid and heat flow relationships in a second-order stream in Valles Caldera National Preserve (NM). Log additions created alternating zones of upwelling and downwelling in a reach that was previously losing throughout. By clearing LWD from channels, humans have reduced hydrologic connectivity at the meter-scale and contributed to degradation of benthic and hyporheic habitats. Dams also significantly alter hydrologic connectivity in modern rivers. Continuous water table measurements show that 15 km downstream of the Longhorn dam (Austin, Texas), river stage fluctuations of almost 1 m induce a large, unsteady hyporheic exchange zone within the bank. Dam-induced hyporheic exchange may impact thermal and geochemical budgets for regulated rivers. Together, these three case studies broaden our understanding of complex drivers of hyporheic exchange in small, natural streams as well as large, regulated rivers.
Compressibility and permeability of Gulf of Mexico mudrocks, resedimented and in-situ
(2014-05) Betts, William Salter; Flemings, Peter Barry, 1960-
Uniaxial consolidation tests of resedimented mudrocks from the offshore Gulf of Mexico reveal compression and permeability behavior that is in many ways similar to those of intact core specimens and field measurements. Porosity (n) of the resedimented mudrock also falls between field porosity estimates obtained from sonic and bulk density well logs at comparable effective stresses. Laboratory-prepared mudrocks are used as testing analogs because accurate in-situ measurements and intact cores are difficult to obtain. However, few direct comparisons between laboratory-prepared mudrocks, field behavior, and intact core behavior have been made. In this thesis, I compare permeability and compressibility of laboratory-prepared specimens from Gulf of Mexico material to intact core and field analysis of this material. I resediment high plasticity silty claystone obtained from Plio-Pleistocene-aged mudrocks in the Eugene Island Block 330 oilfield, offshore Louisiana, and characterize its compression and permeability behavior through constant rate of strain consolidation tests. The resedimented mudrocks decrease in void ratio (e) from 1.4 (61% porosity) at 100 kPa of effective stress to 0.34 (26% porosity) at 20.4 MPa. I model the compression behavior using a power function between specific volume (v=1+e) and effective stress ([sigma]'v): v=1.85[sigma]'v-⁰̇¹⁰⁸. Vertical permeability (k) decreases from 2.5·10-¹⁶ m² to 4.5·10-²⁰ m² over this range, and I model the permeability as a log-linear function of porosity (n): log₁₀ k=10.83n - 23.21. Field porosity estimates are calculated from well logs using two approaches; an empirical correlation based on sonic velocities, and a calculation using the bulk density. Porosity of the resedimented mudrock falls above the sonic-derived porosity and below the density porosity at all effective stresses. Measurements on intact core specimens display similar compression and permeability behavior to the resedimented specimens. Similar compression behavior is also observed in Ursa Basin mudrocks. Based on these similarities, resedimented Gulf of Mexico mudrock is a reasonable analog for field behavior.
Consolidation and grain size measurement on the Cape Fear slide complex
(2024-05) Farnsworth, Mason Luke; Daigle, Hugh; Espinoza, David N.
The Cape Fear slide complex is well known for is large failure size. Many slope failures on passive margins can reach catastrophic volumes capable of ruining deep sea infrastructure and can even result in tsunamis that affect coastal communities. These passive margins do not have frequent seismic activity, and many studies have researched the cause for the slope failure. Salt diapirism, regional tectonics and gas hydrate dissociation have all been mentioned as possible causes. Many different petrophysical and geomechanical characteristics, like permeability and compression index, can play a part in these slope failures as well. A 33-day research cruise brought back seismic and core data to aid in giving context to the sediments on the Cape Fear slide. My research aims to provide context to the geological characteristics of the sediment on the Cape Fear slide. A CRS consolidation test is performed and analyzed for 11 of the cores collected, and afterwards, a grain size measurement test was conducted on the trimmings left over from the consolidation tests. Further evaluation of these tests provided data on each core sample. The cumulative data was evaluated for significant relationships and compared with previous studies. A summary of each sample and its data is provided.
Core-scale heterogeneity and dual-permeability pore structure in the Barnett Shale
(2014-12) Cronin, Michael Brett; Flemings, Peter Barry, 1960-
I present a stratigraphically layered dual-permeability model composed of thin, alternating, high (~9.2 x 10⁻²⁰ m²) and low (~3.0 x 10⁻²² m²) permeability layers to explain pressure dissipation observed during pulse-decay permeability testing on an intact Barnett Shale core. I combine both layer parallel and layer perpendicular measurements to estimate layer permeability and layer porosity. Micro-computed x-ray tomography and scanning electron microscopy confirm the presence of alternating cm-scale layers of silty-claystone and organic-rich claystone. I interpret that the silty-claystone has a permeability of 9.2 x 10⁻²⁰ m² (92 NanoDarcies) and a porosity of 1.4% and that the organic-rich claystone has a permeability of 3.0 x 10⁻²² m² (0.3 NanoDarcies) and a porosity of 14%. A layered architecture explains the horizontal (k [subscript H] = 107 x 10⁻²¹ m²) to vertical (k [subscript V] = 2.3 x 10⁻²¹ m²) permeability anisotropy ratio observed in the Barnett Shale. These core-scale results suggest that spacing between high-permeability carrier beds can influence resource recovery in shales at the reservoir-scale. I also illustrate the characteristic pulse-decay behavior of core samples with multiple mutually-orthogonal fracture planes, ranging from a single planar fracture to the Warren and Root (1963) "sugar cube" model with three mutually-orthogonal fracture sets. By relating sub core-scale matrix heterogeneity to core-scale gas transport, this work is a step towards upscaling experimental permeability results to describe in-situ gas flow through matrix at the reservoir scale.
Dependence of transport properties on grain size distribution
(2016-12) Tripp, Brandon Jamal; Daigle, Hugh
The topic of this thesis is investigating the relationship between grain size distribution and absolute permeability for medium silt to very fine-grained sandstones that are typical reservoir rocks in deepwater, offshore environments. I analyzed the relationship between grain size, mean grain size, median grain size, and grain size mode; grain size standard deviation; and absolute permeability through the amalgamation of numerical modeling and experimental core data for marine clay from the Pacific Ocean and Gulf of Alaska. The Pacific Ocean core sample was selected to represent porous media exhibiting narrow grain size distributions; the Gulf of Alaska samples were selected to represent porous media exhibiting broad grain size distributions. I constructed porous media composed of random packings of spheres with grain size distributions modeled on the grain size distribution of the Pacific Ocean core, and determined permeability by performing Lattice-Boltzmann simulations. The narrow grain size distributions exhibited a power law relationship between grain size standard deviation and permeability relationship. I then compared these results to measured data on the Gulf of Alaska samples, which exhibited very broad grain size distributions. The Gulf of Alaska samples had a different relationship between permeability and the standard deviation of the grain size distribution, although the relationship was still a power law. This illustrates how the breadth of the grain size distribution must be considered in empirical permeability relationships.
Determining Permeability Anisotropy From a Core Plug Using a Minipermeameter
(1989-05) Young, Gordon Robert; Lake, Larry W.
The steady-state continuity equation for a real gas is solved using finitedifferences with the boundary conditions for a minipermeameter having an elliptical or circular injection tip seal. The resulting pseudo-potential distribution for the cylindrical domain of a core plug sample is obtained for various permeability ratios. Geometric factors are then calculated by numerically integrating the mass fluxes at the inlet surface inside the injection tip seal. Using a generalized form of Darcy's law, the geometric factors, and data from minipermeameter measurements, estimates of the permeability ratio of four core plug samples are obtained using the geometric factor ratio approach assuming planar isotropy. Finally, quantitative estimates of kx and ky are calculated based on an elliptical and four circular tip seals.
Development of a PES-zeolite fuel cell humidification membrane and humidification membrane analysis system
(2017-08) Borduin, Russell James; Li, Wei (Of University of Texas at Austin); Chen, Dongmei M; Chen, Jonathan Y; Crawford, Richard H; Seepersad, Carolyn C
The purpose of this study is to develop PES-zeolite mixed matrix membranes for use in fuel cell humidification and to study their water permeability as well as physical and thermal properties. A solvent casting process was used to develop the initial PES zeolite mixed matrix membranes (MMM), followed by solid state foaming to alter their morphology and create a porous microstructure. The effects of zeolite weight loading and solid state foaming duration on membrane water permeability were investigated. The best performing films achieved water permeation measurements close to that of Nafion. Next, an extrusion and hot pressing process was developed to replace solvent casting and create PES-zeolite MMM with improved zeolite dispersion. The extruded films were then solid state foamed. The effects of zeolite weight loading and foaming on water permeability, mechanical properties and thermal properties were investigated. Improved zeolite dispersion allowed the extruded films to achieve excellent permeation performance with improved tensile strength. Dynamic mechanical analysis revealed the PES-zeolite membranes have a higher glass transition temperature and storage modulus than Nafion, making them more suited to for use in high temperature fuel cell operation. Finally, a rapid membrane measurement system was developed and modeled to aid in evaluation of small size (<2 cm²) membrane materials.
Effect of network structure modifications on the light gas transport properties of cross-linked poly(ethylene oxide) membranes
(2009-05) Kusuma, Victor Armanda; Freeman, B. D. (Benny D.); Yacamán, M. José
Cross-linked poly(ethylene oxide) (XLPEO) based on poly(ethylene glycol) diacrylate (PEGDA) is an amorphous rubbery material with potential applications for carbon dioxide removal from mixtures with light gases such as methane, hydrogen, oxygen and nitrogen. Changing the polymer network structure of XLPEO through copolymerization has previously been shown to influence gas transport properties, which correlated with fractional free volume according to the Cohen-Turnbull model. This project explores strategic modifications of the cross-linked polymer structure and their effect on the chemical, physical and gas transport properties with an aim to develop rational, molecular-based design rules for tailoring separation performance. Experimental results from calorimetric and dynamic thermal analysis studies are presented, along with pure gas permeability and solubility obtained at 35°C. Incorporation of dangling side chains by copolymerization of PEGDA with methoxy-terminated poly(ethylene glycol) methyl ether acrylate, n=8 (PEGMEA) was previously shown to be effective in increasing fractional free volume of XLPEO through the opening of local free volume elements, which in turn increased CO₂ permeability. Through a comparative study ofshort chain analogs to these co-monomers, incorporation of an ethoxy-terminated co-monomer was shown to be more effective than a comparable methoxy-terminated co-monomer in increasing gas permeability. For instance, copolymerization of PEGDA with 71 wt% ethoxy-terminated diethylene glycol ethyl ether acrylate increased CO₂ permeability from 110 barrer to 320 barrer. Gas permeability increase was not observed when hydroxy or phenoxy-terminated pendants were introduced, which was attributed to reduction in chain mobility due to increased inter-chain chemical interactions or steric restrictions, respectively. Based on these results, incorporation of a co-monomer containing a bulky non-polar terminal group, tris-(trimethylsiloxy)silyl, was examined in order to further increase gas permeability. Addition of 80 wt% TRIS-A co-monomer increased CO₂ permeability of cross-linked PEGDA to 800 barrer. However, the resulting changes in chemical character of the copolymer reduced CO₂/light gas selectivity, even as gas permeability increased. The effect of incorporating a bulky, stiff functional group in the cross-linker chain was studied using cross-linked bisphenol-A ethoxylate diacrylate, which showed 40% increase in permeability compared to cross-linked PEGDA. This study affirmed the importance of polymer chain interaction, in addition to free volume, in determining the gas transport properties of the polymer.
Effect of Porosity and Permeability on the Membrane Efficiency of Shales
(2008-08) Osuji, Collins Emenike; Chenevert, Martin E.; Sharma, Mukul Mani
This study presents experimental data showing the dependence of shale membrane efficiency on petrophysical properties and mud composition for water-based muds. Wellbore instability often occurs as a result of osmotic pressures that develop when a shale is in contact with water-based muds. The osmotic pressures generated are proportional to the shale membrane efficiency. A pressure transmission technique was used to measure the membrane efficiency of Atoka and C-5 shale at different porosities. It is not currently possible to directly measure the shale membrane efficiency down-hole. This method may provide a way to estimate shale membrane efficiency from down-hole wire-line formation tester measurements. The results of this study could possibly be used to design muds that produce shale strengthening and result in better wellbore stability. Two series of tests were performed; the first set used brine solution as the test fluid while the second set used three, industry-provided, water-based muds. Results show that the membrane efficiency of Atoka shale ranges from 0.4% to about 13% and is a function of the shale porosity. This shows that the porosity of the shale itself is an important consideration in mud design. The data clearly show that the membrane efficiency is negatively correlated with the shale porosity until a porosity of about 7.5%, beyond which there is essentially no change in membrane efficiency. A good correlation was also found between the shale permeability (which is in the order of 0.1 nD) and the membrane efficiency. Above a permeability of 0.2 nD, osmotic effects were measured to be small. For tests conducted with water-based muds, the membrane efficiency of the shale was reduced by a factor of more than 2 after contacting two of the three muds with the mud-altered Atoka shale. This decrease was found to correlate very well with an increase in porosity and permeability in the shale. However, muds that reduced the permeability exhibited an increase in membrane efficiency. This shows the importance of porosity- and permeability-reducing agents in changing the membrane efficiency and osmotic pressure in shales. Shale membrane efficiency has been shown to correlate with the shale porosity and permeability. Interaction of the shale with different water-based muds is shown to change the membrane properties of the shale. Furthermore, the nature of this change determines the effectiveness of these muds in the stabilization of troublesome shales. This is important because of the time-dependent nature of wellbore failure. This study shows that certain drilling fluids have the ability to alter the shale through permeability reduction induced by osmotic flow. The results of the study can be used to design better water-based drilling fluids that will stabilize shales.
Effect of rough fractal pore-solid interface on single-phase permeability in random fractal porous media
(2016-08) Cousins, Timothy Alexander; Daigle, Hugh; Prodanović, Maša
Single-phase permeability k has intensively been investigated over the past several decades by means of experiments, theories and simulations. Although the effect of surface roughness on fluid flow and permeability in single pores and fractures as well as in a network of fractures was studied previously, its influence on permeability in a random mass fractal porous medium constructed of pores of different sizes remained as an open question. A fractal medium is one whose pore space and solid matrix can be characterized by statistical self-similarity and described by a fractal dimension Dm. Specifically, in a random mass fractal, each iteration of construction of the medium is composed of identical-size particles and pores of different sizes that are distributed randomly within (Hunt et al. 2014). This thesis contains the research into the effect of rough pore-solid interface on single-phase flow and permeability in fractal porous media. Using fractal geometry, randomly generated three-dimensional Menger sponges were created to model porous media with a range of mass fractal dimensionalities Dm between 2.579 and 2.893. This dimensionality characterizes both the solid matrix and the pore space of the media. The pore-solid interface of the media is subsequently roughened using the Weierstrass-Mandelbrot approach and controlled primarily by the surface fractal dimension Ds and root-mean-square of roughness height σ. The permeability was calculated for all the roughened media using the lattice-Boltzmann method using D3Q19 geometry and Bhatnagar-Gross-Krook (BGK) collision model. The LBM simulations calculated the single-phase permeability based on Darcy’s Law. Results indicate that permeability decreases sharply with increasing Ds from 1 to 1.1 regardless of Dm value, and remains relatively constant as Ds increases from 1.1 to 1.6. Furthermore, while creating the media, a lower bound for the percolation threshold appeared to be around 29.8% for randomized Menger sponges. When fitted to the percolation model presented in Larson et al. (1981) with an upper limit of 0.36 from Kim et al. (2011), the parameters from a least squares fit point to a critical porosity ϕc of 30% and a percolation exponent t between 3.1 and 3.3. Future research should investigate the effect of the percolation threshold for these simulated porous media and the effect surface roughness would have on this threshold. Finally, future research should expand into two-phase flow and investigate the effects of surface roughness on relative permeability and capillary pressure in simulated fractal porous media.
The Effect of Stress Paths and Shear Failure on the Permeability of Unconsolidated Sands
(2008-08) Yaich, Elyes; Olson, Jon E.
Heavy oil recovery often involves steam injection, increasing both the pore pressure and temperature of the reservoir. This can lead to changes in in situ stresses that can cause shear failure in unconsolidated sand reservoirs. Volumetric dilation resulting from this failure has been reported to cause permeability increases of anywhere from 10% to an order of magnitude. Variability in these results seems to be related to the confining stress at which the experiments were performed, the degree of compaction of the sample, and the grain mineralogy, size and shape. Other factors like stress path used in the experiments may also play a crucial role in the evolution of permeability during heavy oil recovery. In this study, a series of “confined compressive” tests were run, under both increasing and decreasing mean stress conditions. Sand samples with different grain size distribution and initial porosity were used. During the triaxial compression test, the samples were isotropically loaded to the required confining stress. Then the axial stress was increased while the radial stress was kept constant. In another test, called “radial extension”, the samples were first isotropically loaded to a specific stress after which the radial stress was reduced while the axial stress was kept constant. During these tests, axial and radial stresses, axial and volumetric strains and, permeability were determined. In general, the finer grained sands had smaller initial permeabilities than the coarser grained samples, but the finer grained samples showed the greatest percentage permeability increase during shear dilatancy. The results showed a maximum permeability improvement of 42% during radial extension tests for fine grained sands at 10% axial strain. These tests were initiated at 200 psi isotropic compression. Under the same loading conditions, a similarly prepared coarse grained sand peaked at 10% permeability increase at 5% axial strain, but had a 10% permeability decrease by 10% axial strain. During triaxial compression tests at 50 psi confining stress, only 12% permeability enhancement was observed for the fine grained sand at 10% axial strain. The permeability increase was 8% for a similarly prepared coarse grained sample. An experiment at a higher confining stress of 200 psi inhibited permeability increase for the triaxial compression test, even though the volumetric strain was still dilatant. A higher initial isotropic stress of 500 psi for the radial extension test, comparable to increased compaction before unloading, enhanced permeability increase by about 10%.
Effect of Structure on Petrophysical Properties of Porous Media
(1994-05) Gao, Yaming; Sharma, Mukul Mani
The objective of this project is to relate the microscopic structure of porous media to macroscopic properties, such as porosity, permeability, dispersion coefficient, and chemical reactivity. In the first part of this study, fluid flow in porous media is simulated by a lattice gas automaton model. The fluid velocity profiles and pressure drops around obstacles of known-shape are calculated. Heterogeneous permeability fields at a macroscopic and megascopic length scale are created by distributing scatterers within the fluid flow field. These scatterers act as obstacles to flow. The loss in momentum of the fluid is directly related to the permeability of the lattice gas model. It is shown that by varying the probability of occurrence of solid nodes, the permeability of the porous medium can be changed over several orders of magnitude. To simulate fluid flow in heterogeneous permeability fields, isotropic, anisotropic, random, and correlated permeability fields are generated. The lattice gas model developed here is used to obtain the effective permeability as well as the local fluid flow field. The method presented here can be used to simulate fluid flow in arbitrarily complex, heterogeneous porous media. The lattice gas automaton model is also applied to the problem of simulating dispersion and mixing in heterogeneous porous media. We demonstrate here that tracer concentration profiles and longitudinal dispersion coefficients can be computed for heterogeneous porous media It is shown that some basic petrographic measurements such as pore perimeter, pore size, and grain surface area can be made from thin sections that can be used to obtain an order of magnitude estimate of flow properties, such as permeability. The reactivity of rock with acid in an acidizing process depends on the geometrical arrangement of various minerals with respect to each other. A model is developed where the minerals are located in accordance with thin section images. Since the rate of reaction of each mineral is known, an erosion process is used to obtain the reactivity of the rock as a function of time. It is shown that this model provides substantially different results than a simple model that is based only on the mineral abundance in the rock matrix. This result can have a significant impact on currently used acidizing simulators.
Energy production and CO₂ storage through multiphase flow experiments in hydrate systems
(2023-12) Murphy, Zachary Walter; Flemings, Peter Barry, 1960-; DiCarlo, David Anthony, 1969-; Waite, William; Cardenas, Meinhard B; Breecker, Daniel; You, Kehua
Gas hydrate is a solid ice-like compound composed of water and gas. In porous media at low temperatures, high pressures, and with sufficient gas, hydrate will form. Hydrate will occupy a fraction of the pore space, which greatly impacts the petrophysical and geomechanical properties of the system. This study investigates the morphology of gas hydrate within porous media and its impact on multiphase fluid flow behavior in these systems. To explore these impacts, I develop a method for forming hydrates in porous media and then perform systematic flow experiments on the hydrate-bearing samples. I first perform two-phase (water and hydrate) and three-phase (gas, water, and hydrate) relative permeability experiments. Through these experiments, I show that in hydrate systems water will always be the wetting phase and gas and hydrate will be the non-wetting phases. I then present a modeling framework for relative permeability in the presence of hydrate that is based on the porous media's characteristics and thermodynamically preferred pore occupancy, unlike most previous models that have fixed pore and tube geometry assumptions. By using the pore occupancy and treating hydrate as a fluid phase, the relative permeability of hydrate-bearing systems can be predicted from measurements of hydrate-free sediment. Lastly, I explore the potential of CH₄ hydrate reservoirs for simultaneous energy production and CO₂ storage. Using a sand-packed 7.6-meter tube saturated with CH₄ hydrate and water, I inject flue gas (CO₂+CH₄) and observe the dissociation of CH₄ hydrate and subsequent formation of CO₂ hydrate. Chromatographic analysis of the effluent gas unveils the formation of distinct compositional zones during this reactive transport process. These experiments illuminate a solidification and dissociation process where hydrate replacement is composed of a complex series of steps that is driven by the combination of fluid flow and thermodynamics. This dissertation advances the understanding of multiphase flow dynamics that are critical to the lifecycle of hydrate systems on both geologic and production timescales. It offers enhanced modeling of multiphase fluid flow and carbon exchange within hydrate systems, which are relevant to other geologic systems like permafrost.
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, Bo
Estimating 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.