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Impact of viscoelastic polymer flooding on residual oil saturation in sandstones
Get PDFtextThe objective of this research was to determine whether the use of polymer compounds with elastic properties can reduce residual oil saturation in porous media below that of brine or inelastic polymerized solutions. One hypothesis is that long-chain polymer molecules experience stress and a resulting strain when they flow through pore throat constrictions. If the fluid residence time in larger pore spaces is insufficient to allow full relaxation, then strain can accumulate. Sufficient strain results in normal forces which can impinge on oil interfaces and potentially mobilize them. A second hypothesis suggests that polymerized solutions can temporarily protect flowing oil filaments from snap off, allowing them to flow longer and de-saturate further than they would otherwise. The approach taken in this thesis was to conduct a series of core floods in several different sandstones using displacement fluids with elasticity ranging from none to those with extremely high relaxation times. Accelerated flow rate was also employed to reduce residence time and maximize the accumulation of elastic strain and normal force potential. Experiments were designed to provide direct comparisons between both non-elastic and elastic floods but also multiple floods with increasing elasticity. The results were inconclusive with some experiments showing additional oil recovery that could be attributed to elastic mechanisms. Most experiments, however, showed no significant difference between elastic and non-elastic floods when experimental parameters were controlled within narrow limits. This research did refine the experimental context in which elastic effects are most likely to be observed. As such, it can serve as a precursor to additional core flooding in oil-wet systems, experiments conducted at reservoir temperature, and those where the pressure gradient of the flood is held constant and the flow rate allowed to vary. Computer aided tomography could also be employed to visualize the mobilization of oil with different displacement fluids, identify where bypassed oil occurs with unstable floods, and determine how oil is subsequently mobilized with better conformance and or elasticity.Petroleum and Geosystems Engineerin
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Nanoparticle dispersion flow for enhanced oil recovery using micromodels
Get PDFtextThe injection of nanoparticles is a promising and novel approach to enhancing oil recovery in depleted fields. Nanoparticles have one dimension that is smaller than 100 nm and have many unique properties that are useful when it comes to oil recovery. Their small size and the ability to manipulate particle properties are a couple of the advantageous properties. The small size of nanoparticle allows them to easily pass through porous media. Manipulating nanoparticle properties allows for wettability modifications or controlled release of chemicals at a precise location in the formation. Injection of nanoparticle dispersions for secondary or tertiary recovery in corefloods has yielded positive results. Field tests using nanoparticles have also yielded positive results with increased oil recovery. While there has been a sizable amount of work related to corefloods, limited investigation has been reported using micromodels. Micromodels are valuable because they allow for pore scale viewing of the oil recovery, which is not possible with corefloods. In this research both polydimethylsiloxane (PDMS) and glass microfluidic devices were fabricated to test the EOR potential of different types of nanoparticles. Much of the work described in this thesis involved the use of a dead-end pore geometry to trap oil. First the pore space was filled with oil and then waterflooded. This left some oil trapped in the dead-end pores. PDMS micromodels proved difficult to trap oil in the dead-end pores; because of this glass micromodels were tested. After trapping oil, a nanoparticle dispersion was injected into the pore space to test the potential of the dispersion to reduce the residual oil saturation in the dead-end pores. The nanoparticle dispersion was injected at different flow rates (1 [mu]l/hr to 50 [mu]l/hr) to test the effect of flow rate on residual oil recovery.Petroleum and Geosystems Engineerin
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Experimental study of microbial enhanced oil recovery and its impact on residual oil in sandstones
Get PDFThe objective of this research project was to determine experimentally, using core floods, whether providing additional nutrients to accelerate the growth of nitrate-reducing bacteria alongside aerobic bacteria would result in an improved oil recovery in sandstone rocks. The hypothesis was that indigenous reservoir microbes only need additional nutrients to be able to alter the forces enacting within an oil-water-rock system drastically. As a microbial population grows, individual bacteria strains may colonize to form biofilm and produce microbial byproducts. In general, enhanced oil production from microbes can be categorized into three mechanisms, fluid diversion, interfacial tension (IFT) reduction, and solvent production. Moreover, the distribution and connectivity of the remaining oil could influence the response time and quantity of additional oil production. From the Computed Tomography experiments conducted in this study, it was made apparent that oil distribution does not change considerably when changing brine injection rate after reaching residual oil saturation. However, future experiments are recommended to determine if the waterflood flow rate before reaching residual oil saturation will influence the distribution of capillary-bound oil. Conventional Microbial Enhanced Oil Recovery (MEOR) projects involving the injection of surface-produced byproducts to release oil has proven to be costly, inefficient, and unpredictable. Recent research suggests stimulating indigenous reservoir microbes with inorganic nutrients would increase oil production in a cost-effective manner. In this study, an optimal methodology of conducting microbial corefloods with live reservoir microbes and inorganic nutrients is devised. Corefloods performed in absence of sodium dithionite had overall better microbial growth. Experiments conducted with 1% salinity brine yielded little tertiary oil production (0.1% Sor reduction). MEOR experiments in both 2.5 and 5% salinity systems showed significantly more oil release (1 to 6.5% Sor reduction). Furthermore, secondary waterflood flow rate did have an impact on the tertiary oil recovery (more than 5% difference in Sor reduction). The work presented in this study can be used as a precursor to analyze MEOR performance on high viscosity oil or in heterogeneous rocks.Petroleum and Geosystems Engineerin
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Database, Spreadsheet, and Models for Polymer Chemical Enhanced Oil Recovery
Get PDFPolymer chemical enhanced oil recovery (EOR) is a tertiary method of oil production that
helps to improve the recovery of hydrocarbons in the late stages of a reservoir’ s life.
This method of EOR increases the amount of unswept or residual oil produced by
displacing and driving the fluids towards a producing well. Polymers are used in chemical
EOR to improve the mobility ratio. The objectives of this research were to develop a
predictive model to find the shear rate versus viscosity of a polymer sample without the
need for lab input data, to create a program to model and validate the accuracy of large
data sets simultaneously, and to combine common polymer calculations/programs into a
Master Polymer Tool. This multi-faced work involved the use of lab work, numerous
modeling techniques, and programming to achieve these outlined objectives. The
predictive model was able to model the rheology of a polymer sample, while the program
efficiently processed large amounts of polymer rheology data for modeling, quality
validation, and to observe a macroscopic analysis of polymer behavior. Though there is a
wide degree of variability in polymer data – in large part due to inconsistencies in
preparation – current predictive modeling techniques were found to be accurate
indicators of rheological behavior. Numerous other programs and spreadsheets related to
polymer EOR were updated and combined into a Master Polymer Tool to provide
researchers and engineers with a “ one stop shop” for commonly used calculations.Petroleum and Geosystems Engineerin
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New polymer rheology models based on machine learning
Get PDFA successful polymer-type EOR project relies upon many factors, including an adequate characterization, description, and prediction of the polymer’s rheology. A high polymer viscosity can improve the mobility and sweep efficiency, but can also lead to poor injectivity. Polymers are generally non-Newtonian and the rheology is a function of in-situ shear rate, polymer concentration, salinity, temperature, molecular weight, and molecular structure. A priori estimation of polymer rheology using models is important for design of polymer floods and prediction using numerical reservoir simulators. Existing models require many fitting parameters, are purely empirical, and can rarely be used for a priori estimation. The objective of this work was to develop new models to predict the viscosity of HPAM polymers used in enhanced oil recovery (EOR) and implement them into a chemical flooding numerical reservoir simulator. The study uses a combination of fundamental, physical models and machine learning methods to develop new predictive models. The data used in the study includes the measured polymer rheology at various polymer concentrations, molecular weights and types, temperatures, and brine salinity and hardness. Data are first fit to the 4-parameter Carreau’s model and then advanced machine learning techniques are used to develop the models of the Carreau parameters with the aforementioned solution properties. The models are then used to predict the rheology of new samples which are validated against data measured on an ARES G2 rheometer. All data fit the 4-parameter Carreau model well. The new models for the zero-shear viscosity, shear thinning index, and time constant are a function of temperature, polymer concentration, salinity, hardness, and molecular weight using less than ten parametersPetroleum and Geosystems Engineerin
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Experimental investigation of low interfacial tension displacements in oil-wet, fractured micromodels
Get PDFThe objective of this work was to determine, using a microfluidics platform, if surfactants that reduce interfacial tension would produce oil from oil-wet, fractured systems in both static conditions (where no injection was involved) and in dynamic conditions (where fluid was injected into the system).
The hypothesis was that as surfactants reduce interfacial tension between oil and water in an oil-wet, fractured porous medium, forces of very small magnitude (hydrostatic force created by a brine column less than 10 centimeters high, or transverse viscous pressure gradients) should overcome capillary forces and desaturate oil from the porous medium.
Experiments where an oil-wet rock core is immersed in surfactant solution have shown surfactants can desaturate oil from oil-wet cores. Flooding experiments where surfactant is injected into fractured cores showed that viscous pressure gradients can aid in oil production from these types of rocks. In this work, micromodels fabricated using advanced fabrication methods were used to visualize oil production from oil-wet, fractured systems. Glass micromodels were made oil-wet using alkyl-silanes and designed to have large permeability contrasts (>1000) between the pore-grain array and the fractures.
To measure the effect of wettability on production, micromodels were immersed in brine and surfactant solution baths while lying flat on a surface (to minimize gravity forces) and oil saturation was measured over time. After 31 days, no oil was produced from the micromodel immersed in brine, and about 50% was produced from the micromodel immersed in the surfactant solution. The effect of gravity forces was examined by immersing micromodels in brine and surfactant solution baths while positioned vertically. Minimal (4%) oil desaturation was observed in the brine-immersed micromodel while approximately 75% desaturation was observed in the micromodel immersed in surfactant after 10 hours. Finally, dynamic experiments were conducted where brine followed by the surfactant solution were injected directly into a high permeability fracture that had a pore-grain array adjacent to it. No matrix desaturation was observed for the water flood, while approximately 25% oil-desaturation from the matrix was observed after 1 PVI of the surfactant solution.
Recovery using surfactants was fast (in the order of hours) for experiments with imposed forces (gravity, transverse viscous pressure drop), and slow (in the order of days/weeks) for experiments without imposed forces. After visualizing surfactant floods in oil-wet, fractured micromodels under different flow conditions (negligible gravity, gravity driven, injection driven) it was concluded that low IFT is needed in order to reduce capillary forces so that very small driving forces (like the pressure difference created by a water column 5 cm high) can displace oil out of the low permeability matrix. This process can be further enhanced by properly designing the properties of the microemulsion phase, such as the viscosity.Petroleum and Geosystems Engineerin
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Modeling single-phase flow and solute transport across scales
Get PDFtextFlow and transport phenomena in the subsurface often span a wide range of length (nanometers to kilometers) and time (nanoseconds to years) scales, and frequently arise in applications of CO₂ sequestration, pollutant transport, and near-well acid stimulation. Reliable field-scale predictions depend on our predictive capacity at each individual scale as well as our ability to accurately propagate information across scales. Pore-scale modeling (coupled with experiments) has assumed an important role in improving our fundamental understanding at the small scale, and is frequently used to inform/guide modeling efforts at larger scales. Among the various methods, there often exists a trade-off between computational efficiency/simplicity and accuracy. While high-resolution methods are very accurate, they are computationally limited to relatively small domains. Since macroscopic properties of a porous medium are statistically representative only when sample sizes are sufficiently large, simple and efficient pore-scale methods are more attractive. In this work, two Eulerian pore-network models for simulating single-phase flow and solute transport are developed. The models focus on capturing two key pore-level mechanisms: a) partial mixing within pores (large void volumes), and b) shear dispersion within throats (narrow constrictions connecting the pores), which are shown to have a substantial impact on transverse and longitudinal dispersion coefficients at the macro scale. The models are verified with high-resolution pore-scale methods and validated against micromodel experiments as well as experimental data from the literature. Studies regarding the significance of different pore-level mixing assumptions (perfect mixing vs. partial mixing) in disordered media, as well as the predictive capacity of network modeling as a whole for ordered media are conducted. A mortar domain decomposition framework is additionally developed, under which efficient and accurate simulations on even larger and highly heterogeneous pore-scale domains are feasible. The mortar methods are verified and parallel scalability is demonstrated. It is shown that they can be used as “hybrid” methods for coupling localized pore-scale inclusions to a surrounding continuum (when insufficient scale separation exists). The framework further permits multi-model simulations within the same computational domain. An application of the methods studying “emergent” behavior during calcite precipitation in the context of geologic CO₂ sequestration is provided.Petroleum and Geosystems Engineerin
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Pore-scale modeling of viscoelastic flow and the effect of polymer elasticity on residual oil saturation
Get PDFtextPolymers used in enhanced oil recovery (EOR) help to control the mobility ratio between oil and aqueous phases and as a result, polymer flooding improves sweep efficiency in reservoirs. However, the conventional wisdom is that polymer flooding does not have considerable effect on pore-level displacement because pressure forces would not be enough to overcome trapping caused by capillary forces. Recently, both coreflood experiments and field data suggest that injecting viscoelastic polymers, such as hydrolyzed polyacrylamide (HPAM), can result in lower residual oil saturation. The hypothesis is that the polymer elasticity provides several pore-level mechanisms for oil mobilization that are generally not significant for purely-viscous fluids. Both experiments and modeling need to be performed to investigate the effect of polymer elasticity on residual oil saturation. Pore-scale modeling and micro-fluidic experiments can be used to investigate pore-level physics, and then used to upscale to the macro-scale. The objective of this work is to understand the effect of polymer elasticity on apparent viscosity and residual oil saturation in porous media. Single- and multi-phase pore-level computational fluid dynamics (CFD) modeling for viscoelastic polymer flow is performed to investigate the dominant mechanisms at the pore level to mobilize trapped oil. Several interesting results are found from the CFD results. First, the elasticity of the polymer results in an increase in normal stress at the pore-level; therefore, the normal stresses exerted on a static oil droplet are significant and not negligible as for a purely-viscous fluid. The CFD results show that viscoelastic fluid exerts additional forces on the oil-phase which may help mobilize trapped oil out of the porous medium. Second, due to the elasticity of polymer, the viscoelastic polymer has some level of pulling effect; while passing above a dead-end pore it can pull out the trapped oil phase and then mobilize it. However, both CFD modeling and micro-fluidic experiments show the pulling-effect is not likely the main mechanism to reduce oil saturation at pore-level. Third, dynamic CFD simulations show less deformation of the oil phase while viscoelastic polymer is displacing fluid compared to purely viscous fluid. It may justify the hypothesis that polymer elasticity resists against snap-off mechanism. As a result, when viscoelastic polymer displaces the oil ganglia, the oil phase does not snap off, and the oil phase remains connected, and therefore easier to move in porous media compared to disconnected oil. For single phase flow, a closed-form flow equation has been developed based on CFD modeling in converging/diverging ducts representative of pore throats. The pore-level equations were substituted into a pore-network model and validated against experimental data. Good agreement is observed. This study reveals important findings about the effect of polymer elasticity to reduce the residual oil saturation; however, more experiments and simulations are recommended to fully-understand the mobilization mechanisms and take advantage of them to optimize the polymer-flooding process in the field.Petroleum and Geosystems Engineerin
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Using mortars to upscale permeability in heterogeneous porous media from the pore to continuum scale
Get PDFtextPore-scale network modeling has become an effective method for accurate prediction and upscaling of macroscopic properties, such as permeability. Networks are either mapped directly from real media or stochastic methods are used that simulate their heterogeneous pore structure. Flow is then modeled by enforcing conservation of mass in each pore and approximations to the momentum equations are solved in the connecting throats. In many cases network modeling compares favorably to experimental measurements of permeability. However, computational and imaging restrictions generally limit the network size to the order of 1 mm3 (few thousand pores). For extremely heterogeneous media these models are not large enough in capturing the petrophysical properties of the entire heterogeneous media and inaccurate results can be obtained when upscaling to the continuum scale. Moreover, the boundary conditions imposed are artificial; a pressure gradient is imposed in one dimension so the influence of flow behavior in the surrounding media is not included.
In this work we upscale permeability in large, heterogeneous media using physically-representative pore-scale network models (domain ~106 pores). High-performance computing is used to obtain accurate results in these models, but a more efficient, novel domain decomposition method is introduced for upscaling the permeability of pore-scale models. The medium is decomposed into hundreds of smaller networks (sub-domains) and then coupled with the surrounding models to determine accurate boundary conditions. Finite element mortars are used as a mathematical tool to ensure interfacial pressures and fluxes are matched at the interfaces of the networks boundaries. The results compare favorably to the more computationally intensive (and impractical) approach of upscaling the media as a single model. Moreover, the results are much more accurate than traditional hierarchal upscaling methods. This upscaling technique has important implications for using pore-scale models directly in reservoir simulators in a multiscale setting. The upscaling techniques introduced here on single phase flow can also be easily extended to other flow phenomena, such as multiphase and non-Newtonian behavior.Petroleum and Geosystems Engineerin
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Pore network modeling of carbonate acidization
Get PDFtextOver half of the world's hydrocarbon reserves are found in carbonates. Acid injection is a cost effective way to enhance productivity in carbonates by reducing the near-wellbore skin. Ideally, injected acid creates highly permeable channels around the wellbore, known as wormholes. The successful formation of these wormholes depends on acid type, injection rate, and reservoir properties. Improper treatment design results in sub-optimal acid placement with negligible permeability increase. Previous attempts to accurately capture the wormholing process using a pore-scale network model have encountered many difficulties. We present a modern pore network model of carbonate acidization using networks extracted from CT scans of carbonate cores. A mass transfer coefficient and pore merging criterion are developed using finite element simulations in COMSOL that both greatly improve network physics. While there are many weaknesses to the pore network modeling approach, the optimal Damkohler number for our networks closely matches experimental data.Petroleum and Geosystems Engineerin
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