Flow assurance is a critical problem in the oil and gas industry, as an increasing number of wells are drilled in deep water and ultra-deep water environments. High pressures and temperatures as low as 2° C in these environments hinder flow of hydrocarbon-based fluids by formation of methane hydrate and wax. Commonly used methods for flow assurance in flowlines are chemical injection and direct electric heating which face several limitations. In this paper, an application to use superparamagnetic nanoparticle-based heating for flow assurance, in the form of a magnetic nanopaint is presented. Superparamagnetic nanoparticle-based heating has been extensively researched in the biomedical industry for cancer treatment by hyperthermia. Superparamagnetic nanoparticles in dispersions generate heat by application of an oscillating magnetic field as explained by Neel’s relaxation theory. In our application, superparamagnetic Fe3O4 nanoparticles are embedded in a thin layer of cured epoxy termed ‘nanopaint’. This nanopaint coating on the internal surface of subsea flowlines could generate heat and thus prevent formation of methane hydrates and wax.
In this paper, parameters affecting heating performance of superparamagnetic nanoparticles such as particle size, and magnetic field and frequency are discussed. Rigorous characterization of nanoparticles and nanopaint performed using VSM, TEM etc., is used to quantify heating performance and optimize it. Heating performance of two samples of Fe3O4 nanoparticles varying in size distribution is evaluated in batch experiments and compared to Neel’s relaxation theory. Performance of nanopaint to heat static/batch fluids and flowing fluids is evaluated. Heating performance of superparamagnetic nanoparticles in dispersions and in nanopaint is found to be similar and so it is concluded that Neel’s relaxation theory is applicable to nanopaint. Heating performance of nanopaint is flow experiment is found to be better than in batch experiments by a factor greater than 5.
Flow assurance is the ability to transport hydrocarbon-based fluids economically and safely from the reservoir to production facilities, over the life of the field. With increasing oil and gas production from deep-water and ultra-deep water wells, flow assurance has become a critical problem for the oil and gas industry. Subsea wells are at greater risk of deposit formation due to low temperatures and high pressures in deep water environments. Methane hydrate formation and wax deposition severely limit production rates, pose safety concerns and may also result in the shutdown of the well. Hence various methods are employed for remediation and prevention of flow assurance problems, primarily relying on the principles of temperature increase, pressure reduction or mechanical removal. These methods include use of pigging solutions, chemical additive injection, SGN (nitrogen steam generation) process, direct electric heating, heated pipe-in-pipe (Hpip) solutions and have been previously summarized in . Commonly used methods in the industry are chemical injection and direct electric heating. In chemical injection, a glycol usually methanol is injected into the pipeline to lower the hydrate formation temperature. However, high costs and concentration limits imposed by quality control limit their usage. In direct electric heating, electricity is forced through tracer cables laid along the length of the flowline. Temperature can be controlled by varying the power input to the system and variable heating rates can be obtained. However, there is risk of electricity leakage and component failure due to excessive heating. In this paper, we use superparamagnetic nanoparticle-based heating to address the issue of flow assurance.
Wang, Qing (The U. of Texas at Austin) | Prigiobbe, Valentina (The U. of Texas at Austin) | Huh, Chun (The U. of Texas at Austin) | Bryant, Steven Lawrence (The U. of Texas at Austin) | Mogensen, Kristian (Maersk Oil Research & Technology Centre) | Bennetzen, Martin Vad (Maersk Oil Research & Technology Centre)
Divalent cations, especially calcium (Ca2+), are known to significantly affect the performance of anionic surfactants and polymers used in enhanced oil recovery (EOR) processes. An efficient technique to remove Ca2+ from brine is reported, which is based on selective adsorption of Ca2+ onto functionalized iron oxide magnetic nanoparticles (IOMNPs). Upon adsorption, the IOMNPs can be separated by applying a magnetic field, leaving behind softened water.
IOMNP was synthesized by coprecipitation, and the amine-functionalization of its surface was obtained according to an aqueous APTES coating process. Chelating agent, polyacrylic acid (PAA), was successfully coated on amine-functionalized IOMNPs via amidation of carboxylic acid using 1-ethyl-3-(3-dimethylaminopropyl) carbodiimide (EDC). PAA modification significantly enhanced the adsorption capacity of IOMNPs due to their great ability to chelate Ca2+. The effect of pH on adsorption capacity was also investigated. The adsorption capacity of Ca2+ onto PAA-IOMNPs was found to be as high as 57.2 mg/g at pH 7 from the 400 mg/L Ca2+ solution. However, in American Petroleum Institute (API) standard brine (8×104 mg/L NaCl and 2×104 mg/L CaCl2), the adsorption capacity of IOMNPs decreased to 9.8 mg/g since the high salinity screens the charges on the surface of PAA-IOMNPs and results in the formation of nanoparticle aggregates. PAA-IOMNPs can be reused after treated by acetic acid solution.
A geochemical model was developed to describe the competitive adsorption of Ca2+ and H+ onto amine-functionalized IOMNPs as a function of solution pH and Ca2+ concentration. Comparison between the model and the experiments shows that the adsorption isotherms predict the behavior of the system very well. Below pH 4, adsorption of Ca2+ is negligible and becomes important above pH 7. This opens the possibility of recovering the nanoparticles after the divalent cation removal, and reusing them for the repeated water softening.
Ko, Saebom (University of Texas At Austin) | Prigiobbe, Valentina (University of Texas at Austin) | Huh, Chun (University of Texas At Austin) | Bryant, Steven Lawrence (University of Texas At Austin) | Bennetzen, Martin Vad (Maersk Oil Research & Technology Centre) | Mogensen, Kristian (Maersk Oil Research & Technology Centre)
The treatment of highly stable small oil droplets in produced water is challenging for offshore production, where platform space is constrained, because their long residence time requires large equipment volumes. The use of magnetic nanoparticles (MNPs) to remove dispersed droplets is a promising alternative due to their quick response to external magnetic field, allowing easy separation of oil droplets on which MNPs were attached from water. The goal of this study is to prove the concept of magnetically separating oil droplets from produced water using surface-coated MNPs. Batch-scale experiments were performed and they showed that droplets in 5 wt. % of decane-in-water emulsions, which have negative surface charges, were successfully separated from water using cationic surfactant-coated MNPs, with decane removal efficiency of 85 to 99.99%, depending on the experiment conditions. Anionic surfactant-coated MNPs did not remove oil droplets, indicating that the electrostatic attraction between emulsions and MNPs control the attachment of the MNPs to the droplet surface. The settling velocity of a droplet coated with MNPs was derived by extending classical theory to account for the magnetic force as well as buoyancy and drag forces. Under the applied experimental conditions and considering the geometry of the oil-water-MNP system, velocity calculations show that the droplet settles spontaneously when a magnetic field is applied. Otherwise the MNP-coated oil droplets (MNP-droplets) would naturally migrate upwards due to buoyancy. The velocity of a single MNP-droplet is strongly dependent on the intensity of the magnetic field and it changes up to three orders of magnitude within the height of tested sample of approximately 3 cm.
During oil recovery processes, a large volume of water is produced, as much as 20 times of the oil, and the treatment of the produced water for re-use or safe disposal is generally one of the largest oil-field operating expense. One major component of the produced water treatment is the removal of the highly stable dispersed oil. U. S. Environmental Protection Agency (USEPA) requires a zero oil discharge for all produced water during the onshore production. For offshore production, USEPA limits the discharge of oil and grease in produced water to a daily maximum of 72 mg/L and a 30-day average of 48 mg/L (USEPA, 2004). However, about 60% of offshore platforms in Gulf of Mexico are believed not to be able to reach USEPA discharge requirement (Thoma et al. 1999). The Convention for the Protection of Marine Environment of the North-East Atlantic (2005) further limits the sea discharge for dispersed oil to 40 mg/L.
Several treatment technologies are currently employed to remove the dispersed oil from produced water, such as gas flotation, coalescers, gravity oil separation, membrane, and chemical oxidation (Ahmadum et al. 2009). For offshore operations, due to the platform space constraints, compact treatment systems are required. In this context, removal of small oil droplets are especially challenging because long residence times and hence large equipment volumes are typically required. Therefore, there have been increasing attention and efforts to find efficient and cost-effective treatment technologies to treat produced water.
Use of specially surface-coated magnetic nanoparticles (MNP), that can be moved and/or assembled in a controlled manner with application of external magnetic field, is drawing considerable interest in recent years, and their applications are being developed exponentially in many disciplines, for example, for drug delivery in pharmaceutics, DNA and cell tagging and separation in biology and medicine, information storage in electronics, environmental/green chemistry, catalysts, and sensors (Klabunde, 2001). Petroleum industry is also actively pursuing MNP technologies as a potential solution to many challenging oilfield problems (Matteo et al. 2012).
Zhang, Tiantian (University of Texas at Austin) | Murphy, Michael (University of Texas at Austin) | Yu, Haiyang (University of Texas at Austin) | Bagaria, Hitesh G. (University of Texas at Austin) | Yoon, Ki Youl (University of Texas at Austin) | Nielson, Bethany M. (University of Texas at Austin) | Bielawski, Christopher W. (University of Texas at Austin) | Johnston, Keith P. (University of Texas at Austin) | Huh, Chun (University of Texas at Austin) | Bryant, Steven Lawrence (University of Texas at Austin)
Nanoparticles (D ~ 5 to 50 nm) easily pass through typical pore throats in reservoirs, but physicochemical attraction between nanoparticles and pore walls may still lead to significant adsorption. We conducted an extensive series of nanoparticle transport experiments in core plugs and in columns packed with crushed sedimentary rock, systematically varying flow rate, type of nanoparticle, dispersion concentration, number and sizes of dispersion slugs, and column grain size. Effluent nanoparticle concentration histories were measured with fine resolution in time, enabling evaluation of nanoparticle adsorption in the columns during flow of dispersion and of postflushes. We also apply this analysis to transport experiments reported in the literature.
Our analysis indicates that nanoparticles undergo both reversible and irreversible adsorption. Effluent nanoparticle concentration reaches the injection concentration during slug injection, indicating the existence of an adsorption capacity. Experiments with a variety of nanoparticles and lithologies yield a wide range of adsorption capacities (from 10-7 to 10-2 g nanoparticle/g porous medium) and a wide range of proportions of reversible and irreversible adsorption. Reversible and irreversible adsorption sites are distinct and interact with nanoparticles independently of each other. The adsorption capacities are typically much less than monolayer coverage but are not an intrinsic property of the porous medium nor of the nanoparticle. Instead, they are influenced by operating conditions, i.e., increasing with larger injection concentration and smaller flow rate.
Aroonsri, Archawin (University of Texas at Austin) | Worthen, Andrew J. (University of Texas at Austin) | Hariz, Tarek (University of Texas at Austin) | Johnston, Keith P. (University of Texas at Austin) | Huh, Chun (University of Texas At Austin) | Bryant, Steven Lawrence (University of Texas At Austin)
Foams used for mobility control in CO2 flooding, and for more secure sequestration of anthropogenic CO2, can be stabilized with nanoparticles, instead of surfactants, bringing some important advantages. The solid nature of the nanoparticles in stabilized foams allows them to withstand the high-temperature reservoir conditions for extended periods of time. They also have more robust stability because of the large adsorption energy required to bring the nanoparticles to the bubble interface.
Silica nanoparticle-stabilized CO2-in-brine foams were generated by the co-injection of CO2 and aqueous nanoparticle dispersion through beadpacks, and through unfractured and fractured sandstone cores. Foam flow in rock matrix and fracture, both through Boise and Berea sandstones, was investigated. The apparent viscosity measured from foam flow in various porous media was also compared with that measured in a capillary tube, installed downstream of beadpacks and cores.
The domain of foam stability and the apparent foam viscosity in beadpacks was first investigated with focus on how the surface wettability of nanoparticles affects the foam generation. A variety of silica nanoparticles without any surface coating and with different coatings were tested, and the concept of hydrophilic/CO2-philic balance (HCB) was found to be very useful in designing surface coatings that provide foams with robust stability. Opaque, white CO2-in-water foams (bubble diameter < 100 µm) were generated with either polyethyleneglycol-coated silica or methylsilyl-modified silica nanoparticles with CO2 densities between 0.2 and 0.9 g/cc. The synergistic interactions at the surface of nanoparticles (bare colloidal silica) and surfactant (caprylamidopropyl betaine) in generating stable CO2 foams were also investigated.
The common and distinct requirements to generate stable CO2 foams with 5-nm silica nanoparticles, in rock matrices and in fractures, were characterized by running foam generation experiments in Boise and Berea sandstone cores. The threshold shear rates for foam generation in matrix and in fracture, both in Boise and Berea sandstones, were characterized. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous, because high shear rates are associated with high permeability zones and fractures. Reducing CO2 mobility in these zones with foam diverts CO2 into lower permeability regions that still contain unswept oil.
Using a previously described model, we estimate the effective permeabilities of about 300 wellbores in six different fields that exhibit sustained casing pressure (SCP) or surface casing vent flow (SCVF). Uncertain parameters that affect the estimated permeability, such as the location of the leak source, are accounted for by a Monte-Carlo simulation approach, yielding an expected value of leakage path permeability for each measurement of SCP or SCVF. Characterizing leakage paths can be useful in diagnosing and remediating poor zonal isolation. This can be particularly valuable in quantifying the likelihood that shallow groundwater is being contaminated by operations in deeper formations, such as shale gas production. Analogous leakage paths are a primary risk factor for large-scale geologic storage of anthropogenic CO2. Being able to estimate CO2 fluxes along existing wellbores is required for quantitative risk assessment.
The expected values of estimated permeabilities along most of the leaky wellbores are between 10 md to 10 md. Using the wellbore permeabilities to estimate the aperture of the leakage pathways, we estimate the capillary pressure and hence the minimum CO2 plume heights required for CO2 to enter the leakage paths. Almost all leakage pathways require very modest plume heights, so capillary effects are unlikely to prevent leakage. We compute worst-case steady CO2 leakage fluxes, finding that over 90% of the fluxes are less than 0.1 ton/m2/yr. The frequency distribution of the effective permeabilities of leaky wellbores is believed to be the most comprehensive compiled to date. It enables quantitative assessment of leakage rates in a risk assessment context, in particular for the hazard of contamination of shallow resources (e.g. groundwater) by CO2 or natural gas.
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.
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.
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.