Aminzadeh-goharrizi, Behdad (University of Texas At Austin) | Huh, Chun (University of Texas At Austin) | Bryant, Steven Lawrence (University of Texas At Austin) | DiCarlo, David A. (The University of Texas at Austin) | Roberts, Matthew
Surface-treated nanoparticles have been shown to stabilize CO2-in-water foam by adhering to the surface of CO2 bubbles and preventing their coalescence. However, to bring the nanoparticles from the bulk phase to CO2/water interface requires an input of mechanical energy. Co-injection of CO2 and an aqueous dispersion of nanoparticles at high rates is known to provide sufficient energy. However, this co-injection is less favorable because of the operational constraint, i.e., injectivity reduction. Here, we show that beneficial effect of nanoparticles, manifested as improved sweep efficiency, occurs even at low shear rates in a drainage displacement.
We inject high-pressure liquid CO2 into sandstone cores initially saturated with brine containing suspended nanoparticles and compare the results with the case with no nanoparticle addition. The water saturation distribution was measured using CT scanning techniques. The results show that the nanoparticles increase sweep efficiency and reduce the gravity override compared to displacements without nanoparticles. The new mechanism described here provides a promising alternative for mobility control in CO2 floods.
A novel method of delivering thermal energy efficiently for flow assurance and for improved heavy oil production/transport is described. The method, an improved form of magnetic induction heating, uses superparamagnetic nanoparticles that generate heat locally when exposed to a high frequency magnetic field oscillation, via a process known as Neel relaxation. This concept is currently used in biomedicine to locally heat and burn cancerous tissues.
Dependence of the rate of heat generation by commercially available, single-domain Fe3O4 nanoparticles of ~10 nm size, on the magnetic field strength and frequency was quantified. Experiments were conducted for nanoparticles dispersed in water, in hydrocarbon liquid, and embedded in a thin, solid film dubbed "nanopaint". For a stationary fluid heat generation increases linearly with loading of nanoparticles. The rate of heat transfer from the nanopaint to a flowing fluid was up to three times greater than the heat transfer rate to a static fluid.
Heating of nanopaint with external magnetic field application has immediate potential impact on oil and gas sector, because such coating could be applied to inner surfaces of pipelines and production facilities. A nanoparticle dispersion could also be injected into the reservoir zone or gravel pack near the production well, so that a thin, adsorbed layer of nanoparticles is created on pore walls. With localized inductive heating of those surfaces, hydrate formation or wax deposition could be prevented; and heavy oil production/transport could be improved by creating a "slippage layer" on rock pore walls and inner surfaces of transport pipes.
Aminzadeh-goharrizi, Behdad (U. of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin) | Hyun Chung, Doo (U Of Texas At Austin) | Roberts, Matthew (U. of Texas at Austin) | Bryant, Steven Lawrence | Huh, Chun
Injecting nanoparticles into the subsurface can have a potential impact on altering both oil recovery and/or CO2 sequestration. In this work we conduct core floods in which a CO2-analogue fluid (n-octane) displaces brine with and without dispersed nanoparticles. We find that the floods with nanoparticles cause
a greater pressure drop, and a change in flow pattern compared to the floods without. Emulsion formation is inferred by measuring the saturation distribution and pressure drop along the core. The results suggest that nanoparticle stabilized emulsion is formed during a drainage process (at low shear rate condition) which acts to reduce the mobility of the injected fluid.
We also perform imbibition experiments, where the nanoparticle dispersion in brine displaces noctane. Here we observe little difference in the flow pattern and pressure drop as a function of nanoparticle concentration. There is an observed accumulation of nanoparticles at the imbibition front,
which suggests that nanoparticles may be used as a tracer of the displacement front.
We investigated the ability of a dispersion of specially surface-treated nanoparticles to stabilize an oil/water emulsion of prescribed internal structure created by flow within a fracture. We hypothesize that for a set of conditions (nanoparticle concentration, salinity, aqueous to organic phase ratio) a critical shear rate exists. That is, for flow rates that exceed this critical shear rate, an emulsion can be created.
Flow experiments were conducted within fractured cylinders of Boise sandstone and of Class H cement. The Boise sandstone core (D = 1 in and L = 12 in) was cut down its length and propped open to a specific aperture with beads. The fracture was saturated with dodecane which was displaced with nanoparticle dispersion, and vice versa while pressure drop across the fracture was recorded. Class H cement cylinders (D = 1 in and L = 3 in) were allowed to set, then failed in tension to create a rough-walled fracture along their length. These fractured cement cylinders were then sealed and encased in epoxy to isolate the fractures. CT scans of the encased fractures were used to determine the aperture width, which is utilized when calculating the shear rate inside of the fracture maintained during an experiment. A dispersion of surface-modified silica nanoparticles and decane were co-injected into both the Boise sandstone and cement fractures and the pressure drop was measured across the fractures at a variety of shear rates. The effluent of each experiment was collected in sample tubes.
Observation of the effluent and pressure drop data both support our hypothesis of emulsion generation being possible once a critical shear rate has been reached. Alteration of the injected phase ratio and increased residence time of the two phases inside of a fracture both affect the amount of emulsification occurring within the fractures. Increasing the residence time of both phases within a fracture allows for more opportunities for emulsification to occur, resulting in a greater amount of emulsion to be generated. Injection of high or low volumetric ratios of nanoparticle dispersion to organic phase results in little amounts of emulsion generation; however, between the nanoparticle dispersion to organic phase ratios of 0.25:1 and 2:1 significant amounts of emulsion are generated once a critical shear rate has been reached.
Worthen, Andrew (U. of Texas at Austin) | Bagaria, Hitesh (University Of Texas At Austin) | Chen, Yunshen (U Of Texas At Austin) | Bryant, Steven Lawrence (U Of Texas At Austin) | Huh, Chun (U. of Texas at Austin) | Johnston, Keith P. (U Of Texas At Austin)
Viscous C/W foams were generated without the use of polymers or surfactants by shearing CO2 and an aqueous phase containing partially hydrophobic silica nanoparticles in a beadpack filled with 180µm glass beads. Silica particles with 50% SiOH coverage were chosen because they have a hydrophilicity that falls between the 42% SiOH optimum foaming ability for A/W foams (Binks and Horozov 2005) and the 67% SiOH which gave maximum O/W emulsion stability (Binks and Lumsdon 2000). These 50% SiOH silica nanoparticles were found to be interfacially active for CO2-water systems, and stabilized the desired curvature of C/W foams. When the HCB of the nanoparticles is tuned to give contact angles less than 90°, the particles reside primarily in the water phase and C/W foams can be formed. Formation of C/W emulsions stabilized solely with nanoparticles is desirable because it does not require solvation of surfactant tails or polymer chains by CO2. Interfacially active nanoparticles can adsorb at the CO2 water interface without the need for solvation in CO2.
Properly designed nanoparticles generated foams that were more stable than foams generated with polymer-coated nanoparticles or with the nonionic surfactant Tergitol™ 15-S-20 alone. Macroscopic observations showed foams generated solely with 50% SiOH nanoparticles stayed bright white and opaque over 23 hours, while foams generated with PEG-coated silica particles or with surfactant alone resolved nearly completely. Foams generated solely with Tergitol™ 15-S-20 were unstable because surfactant molecules dynamically enter and leave the interface and thus do not provide long-term stabilization. Foams generated with PEG-coated silica particles, though initially very viscous, showed poor long-term stability because of the small particle size and poor solvation of PEG chains in CO2. The larger 50% SiOH nanoparticles strongly adsorbed at the CO2-water interface and provided a barrier around the CO2 bubbles, resulting in very stable foams.
Ganjdanesh, Reza (U. of Texas at Austin) | Bryant, Steven Lawrence (U. of Texas at Austin) | Orbach, Raymond (University of Texas) | Pope, Gary Arnold (U. of Texas at Austin) | Sepehrnoori, Kamy (U. of Texas at Austin)
The current approach to carbon capture and sequestration (CCS) from pulverized coal-fired power plants is not economically viable without either large subsidies or a very high price on carbon. Current schemes require roughly a third of a power plant's energy for carbon dioxide capture and pressurization. The production of energy from geopressured aquifers has evolved as a separate, independent technology from the sequestration of carbon dioxide in deep, saline aquifers. A gamechanging new idea is described here that combines the two technologies and adds another: dissolution of carbon dioxide into extracted brine which is then re-injected. A systematic investigation over a range of conditions was performed to explore the best strategy for the coupled process of CO2 sequestration and energy production. Geological models of geopressuredgeothermal aquifers were developed using available data from studies of Gulf Coast aquifers. These geological models were used to perform compositional reservoir simulations of realistic processes with coupled aquifer and wellbore models.
The sequestration of carbon dioxide and other greenhouse gases in deep saline aquifers (Keith, 2009) as well as the extraction of methane and geothermal energy (heat) from deep geopressured-geothermal aquifers (Jones, 1975) have been studied independently in the past. However, capturing and storing CO2 in aquifers is an expensive process without any monetary return on investment. On the other hand, energy extraction from deep geopressured aquifers was abandoned as a result of low natural gas prices in the 70s and 80s (Griggs, 2005), which prevented this process from becoming economically feasible. In this study, we present a new strategy in which the CO2 sequestration and methane/geothermal energy extraction are combined. In fact, we suggest that the cost of the former can be offset by the profits from the latter.
Geologic formations are capable of storing huge amounts of CO2. Specifically, deep saline aquifers are the best candidates for the storage of significant amounts of CO2 emitted by pulverized coal-fired power plants. However, the storage technology faces several constraints. The most important constraint is the cost of the storage process which includes capturing, purifying, pressurizing, and injecting CO2 (Rochelle, 2009). In addition to the storage cost, other possible constraints exist such as the injection capacity of the aquifer and environmental hazards.
Formations of abnormally high pressure and temperature lie along the Gulf Coast of the United States at depths exceeding 10,000 feet. The brine in these formations is saturated with methane. The methane content of this brine is on the order of 30- 45 SCF of methane per barrel and the total amount is estimated to be between 3000 to 46000 TCF (Griggs, 2005). For example, at 34 SCF per barrel, a small geopressured aquifer with a pore volume of 1 billion barrels would hold a volume of dissolved methane of 34 BCF with an energy content of 35 trillion Btu. When CO2 is dissolved in brine saturated with methane, almost all of the methane comes out of the solution and forms a gas phase of almost pure methane (Taggart, 2009). The production of this methane could help offset the cost of CO2 storage. Moreover, the production of methane gas and/or brine saturated with methane while CO2 is being injected will reduce or eliminate concerns about pressure build-up accompanying CO2 injection. This pressure build-up is a key constraint on large-scale sequestration, because it significantly reduces achievable rates of CO2 injection.
Geologic storage of CO2 for atmospheric emissions reductions imposes unique requirements to document containment. Monitoring pressure in strata above the injection interval is a fit-to-purpose technique to document performance of confining system and degree of isolation provided by existing wellbore completions. Field data are collected over two-and-a-half year period during a continuous industrial-scale CO2 injection at an enhanced oil recovery (EOR) site at Cranfield Field, Mississippi. Continuous downhole high-precision pressure and temperature data were collected at a monitoring well at two depths: at the injection interval and at a selected above zone monitoring interval (AZMI). The AZMI is a prevalent non-productive sandstone above the injection zone and a thick confining system.
Pressure data show a perturbation in above zone contemporaneously with pressure elevation in injection zone, which suggests a possible interformational fluid communication via wellbore. Meanwhile temperature data maintain a linear correlation between zones with a consistent differential, which indicates negligible volumes of injection interval fluid being introduced into the AZMI. Interpretation of the data requires a physics-based transport model to illustrate the possibility of wellbore leakage and quantify the rate if leakage exists.
We model the wellbore leakage by coupling the flow in wellbore and a diffusion model in the above zone sand layer. Matching the pressure data yields an effective wellbore permeability in order of tens of darcies. This corresponds to a large flow rate along the pathway which would very likely raise the temperature in the above zone. To gain insight about the temperature response, we model the heat transfer between the fluid in wellbore and the surroundings. The heat transfer coefficient is tuned and justified by modeling the heat conduction in the formation rock. In order for the temperature in above zone to remain unaffected by that in injection zone, the flow rate should be no more than 10 g/s and the corresponding wellbore permeability not exceed a few darcies. This value is at least an order of magnitude smaller than that estimated from the pressure response. Only if the sand layer in above zone is assumed to have a closed boundary within a few hundred feet of the monitoring well can the pressure data and temperature data be made consistent. However the assumption of closed boundary is not very feasible since there is no evidence of the sand layer being closed by faults locally.
We conclude that leakage from the injection zone is very small. The observed pressure increases in the monitoring well are attributed to larger-scale geomechanical phenomena.
Implementing geological carbon sequestration at large scale to mitigate anthropogenic emissions involves the injection of CO2 into deep brine-filled structures. An alternative to injecting CO2 as a buoyant phase is to dissolve it into brine extracted from the storage formation, then inject the CO2-saturated brine into the storage formation. This "surface dissolution?? strategy eliminates the risk of buoyant migration of stored CO2 and mitigates the extent of pressure elevation during injection. The CO2 concentration front shape when it reaches the saturation pressure contour defines the maximum areal extent of CO2- saturated brine and hence the aquifer utilization efficiency.
Heterogeneity of the aquifer reduces the utilization efficiency. We illustrate by comparing utilization efficiency in homogeneous permeability field with that in uncorrelated and correlated heterogeneous fields under same well control. The example cases yield reductions of the utilization efficiency by 9% and 15% of aquifer pore volume respectively.
We develop an optimal control strategy of the injection/extraction wells to maximize the utilization efficiency for heterogeneous aquifers. We propose two objective functions: one intends to improve the areal sweep by minimizing the mismatch between CO2 concentration front and saturation pressure contour; the other directly formulates the utilization efficiency while penalizing zones that contain gas phase CO2. Both approaches significantly improve the aquifer utilization efficiency by delaying the arrival time of CO2 front to saturation pressure contour. In the uncorrelated heterogeneous field, the utilization efficiency is improved by 3% of the aquifer pore volume. In the correlated heterogeneous field, the improvement on utilization efficiency is 9%.
Heterogeneity plays an important role in determining the location of saturation pressure contour within the storage formation. We propose an optimal well placement strategy by placing line-drive injectors in high permeability zone and extractors in low permeability zone, so that the saturation pressure contour is closer to the extractors and thus increases the aquifer utilization efficiency. Illustration on the correlated heterogeneous field shows an improvement of utilization efficiency by 5% using optimal well placement and another 9% combining with the optimal control of injection/extraction rates. A straightforward implication of the optimal well placement is that hydraulically fracturing the injectors improves the aquifer utilization efficiency by increasing the linear nature of the pressure contours.