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Bryant, Steven Lawrence
Removal of Divalent Cations from Brine Using Selective Adsorption onto Magnetic Nanoparticles
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)
Abstract Divalent cations, especially calcium (Ca), are known to significantly affect the performance of anionic surfactants and polymers used in enhanced oil recovery (EOR) processes. An efficient technique to remove Ca from brine is reported, which is based on selective adsorption of Ca 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 Ca. The effect of pH on adsorption capacity was also investigated. The adsorption capacity of Ca onto PAA-IOMNPs was found to be as high as 57.2 mg/g at pH 7 from the 400 mg/L Ca solution. However, in American Petroleum Institute (API) standard brine (8ร10 mg/L NaCl and 2ร10 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 Ca and H onto amine-functionalized IOMNPs as a function of solution pH and Ca 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 Ca 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.
- Geology > Geological Subdiscipline > Geochemistry (0.69)
- Geology > Mineral > Oxide > Iron Oxide (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.90)
Abstract 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 2ยฐ 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. 1. Introduction 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 [1]. 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.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.66)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Flow Assurance (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Gas hydrates (0.94)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.74)
Abstract 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. INTRODUCTION Large scale geological storage is a key technology to reduce anthropogenic emissions of CO2. Safe storage of CO2 in a brinebearing formation is attributed to dissolution, structural and residual phase trapping (Ennis-King and Paterson, 2002; IEA, 2004; IPCC, 2005; Kumar et al., 2005). Injection of supercritical CO2 into deep structures, however, imposes the following risks:The buoyancy of CO2 increases the potential for leakage along geological and human introduced discontinuities, such as fault and leaky wellbores (Pruess, 2004; Huerta et al., 2009; Tao et al., 2010); The pressure elevation in the formation due to injection of CO2 restricts storage rates, possibly quite severely (Luo and Bryant, 2010), and injection above the threshold rate may induce fracturing of the storage formation and possibly seismic activity; Contamination of ground water resources might occur due to CO2 migration. These risks directly result in higher monitoring and insurance costs.
- Europe (1.00)
- North America > United States > Texas (0.68)
Coupled CO2 Sequestration and Energy Production From Geopressured-Geothermal Aquifers
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)
Abstract 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. Introduction 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.
- Europe > Norway > Norwegian Sea (0.44)
- North America > United States > Texas (0.28)
- North America > Canada > Alberta (0.28)
Abstract 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. INTRODUCTION Carbon capture and geological storage (CCS) is a critical technology to reduce anthropogenic emissions of CO2 (IEA, 2004; IPCC, 2005). Large-volume injection of CO2 for sequestration in subsurface geologic reservoirs will typically elevate subsurface reservoir fluid pressure. Elevated pressure has the potential to impact storage integrity (Chiaramonte et al., 2008) and to cause long-term regional environmental effects (Nicot, 2008; Birkholzer et al., 2009). The concept of pressure management in the injection interval via brine extraction has been discussed and could reduce the potential for interformational communication, but does not negate the utility of pressure and temperature monitoring as a surveillance tool for evaluating containment during CCS projects.
- North America > United States > Louisiana (0.67)
- North America > United States > Mississippi > Franklin County (0.24)
- North America > United States > Mississippi > Adams County (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- North America > United States > Mississippi > Little Creek Field (0.99)
- North America > United States > Mississippi > Cranfield Field (0.99)
- North America > United States > Louisiana > Downdip Tuscaloosa-Woodbine Trend Basin > Tuscaloosa Formation (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin (0.99)
Engineered Nanoparticles as Harsh-Condition Emulsion and Foam Stabilizers and as Novel Sensors
Zhang, Tiantian (U. of Texas at Austin) | Espinosa, David (U. of Texas at Austin) | Yoon, Ki Youl (U. of Texas at Austin) | Rahmani, Amir R. (U. of Texas at Austin) | Yu, Haiyang (University of Texas at Austin) | Caldelas, Federico Manuel (Degolyer and MacNaughton) | Ryoo, Seungyup (University of Texas at Austin) | Roberts, Matthew (The University of Texas at Austin) | Prodanovic, Masa (University of Texas at Austin) | Johnston, Keith P. (University of Texas at Austin) | Milner, Thomas E. (U. of Texas at Austin) | Bryant, Steven Lawrence (U. of Texas at Austin) | Huh, Chun (U. of Texas at Austin)
Abstract Nanoparticles, when synthesized in a specific size range and with a special surface coating tailored to achieve certain desired functionalities, exhibit unique properties. This is because they are almost of molecular size but still retain many useful colloidal characteristics. Recent developments on novel potential upstream applications of nanoparticles are reviewed with focus on research at our laboratory. Oil-water emulsions and CO2 foams that have long-term stability under harsh downhole conditions could be employed as alternatives to surfactant-stabilized emulsions and foams for drilling and other applications. Nanoparticles that show minimal retention can be employed as sensing-capability carrier to detect fluid and rock properties of the producing zone. For example, paramagnetic nanoparticles delivered to the target formation could evaluate fluids saturations there, with application of magnetic field and measurement of response. Emulsions stabilized with surface-coated silica nanoparticles remain stable for months at high temperatures. By designing the hydrophilic/hydrophobic nature of surface coating, either oil-in-water or water-in-oil emulsions can be generated, with droplet size approaching uniform ~5 micron diameter, and with strongly shear-thinning rheology. Stable foams of supercritical CO2-in-water have been generated by co-injecting CO2 and silica nanoparticle aqueous dispersion through a glass-bead pack. The domain of foam stability and the apparent foam viscosity (which were 10 to 100 times more viscous than CO2) reveals threshold values of critical shear rate, particle concentration and phase ratio. An extensive series of sand-pack column and core-plug flow experiments revealed the mechanisms controlling retention of silica and paramagnetic iron-oxide nanoparticles in porous media. A wide range of particle loadings (0.1~18 wt%) and different rock samples were employed. With proper coating, retention was below 10% of the injected amount even in low permeability rock and with large particle concentrations. Potential for various novel upstream applications of engineered nanoparticles is demonstrated. Introduction Novel nanoscale structured materials, in the form of solid composites, complex fluids, and functional nanoparticle-fluid combinations, are bringing major technological advances in many industries. A few examples are the extraordinary material strength, elasticity and thermal conductivity of nano-based metal and polymer composites; targeted and programmed delivery of drugs and enhanced imaging of human organs in medicine; and chemical/physical properties of nano sensors. These and many other novel advances are due to the orders-of-magnitude increase in interfacial area and associated excess stress and chemical potential for the nano-structured materials; and some chemical and physical properties that are unique to nanoscale. In the petroleum/geosystems engineering discipline, research and applications of nanotechnology have been very limited. This is because subsurface formations have heterogeneity of all length scale and any treatments have to be carried out through boreholes, so that process control is generally difficult with significant uncertainties. And any process application requires a large volume treatment so that the material/process cost has to be small. Despite the difficulties, the current advances in nanotechnology are such that a judicious choice of potential applications, and carrying out focused research to bring those potentials to practical maturity, will result in quantum benefits to the oil and gas industry. The recent surge of interest on nanotechnology applications in upstream oil industry, as evidenced by the search of the SPE literature, shows that the important potential of the nanotechnology is beginning to be recognized.
Abstract The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. This model should accurately represent the geometry of any discrete leakage pathway, because this geometry strongly affects the coupling between geochemical reactions and geomechanical response. Validating a transport model in advance of large-scale sequestration is difficult because instances of CO2 plumes reaching abandoned wells are presently rare. However, natural gas leakage events along wellbores can provide insights into conductive pathways analogous to those anticipated for CO2 sequestration. We apply a simple transport model to field measurements of sustained casing pressure (SCP) vs. time. We treat as unknowns the effective permeability of the leakage path and the depth at which leakage into the wellbore is occurring. These parameters are useful for forecasting likely leakage rates in sequestration sites located near oil and gas fields and for choosing candidate sites based on past exploration history. For several cases of SCP, conductive pathways (e.g. open fracture, gas channel, micro annulus) must exist to explain the large inferred values of effective permeability. Extended to more SCP wells, this approach can provide a probabilistic distribution of leakage rates given regional and well parameters. For CO2 sequestration purposes this provides a tool to assess the risk of carbon dioxide escape along leaky wells, which is necessary for site selection, permitting, and properly crediting sequestration operations. Introduction The success of any geologic CO2 sequestration operation depends on our ability to ensure that injected CO2 is properly credited and that assets overlying the storage reservoir remain uncontaminated. To achieve both goals we need to verify that CO2 does not leak out of the target formation at a rate large enough to adversely affect other compartments of economic or environmental value. A physics-based model for leakage will be a valuable tool for assessing risks associated with a prospective storage project and for analyzing field observations. The most probable pathways for leakage are faults and wells. Wells provide a relatively direct path to shallower subsurface formations and to the surface, but their geometry and their sealing capability are highly variable. The petroleum industry has extensive experience with leaky wells. In some of these wells, the leakage path involves a cement/steel interface (typically a micro annulus) and/or a conduit within the cement (gas channel or micro fractures). The leakage path terminates at a sealed wellhead, whence the evolution of sustained pressure in the casing annulus. In contrast, the leakage path of primary concern in CO2 sequestration continues outside the casing. The similarity between gas leakage and CO2 migration is in the leakage pathway. Conduits within cement should behave in essentially the same way in both cases. The cement/steel interface relevant to gas well leakage differs in some important ways from the cement/earth interface relevant to CO2 migration. Nevertheless the effective permeabilities of the two types of interface should be of similar magnitude. Thus by studying the nature of leakage pathways in oil and gas wells, we can estimate the range of leakage rates likely to occur in a CO2 sequestration operation. Well Geometry. Construction of each well is a unique event both in terms of planning and implementation. However, all wells share some common features and must perform certain functions. A typical well completion has several strings of casing cemented in place over some interval (Fig. 1). The key functions of a cemented annulus are to provide support for the weight of the casing, protect the steel casing from corrosive fluids, and isolate geologic zones with respect to fluid migration (Nelson and Guillot, 2006). Loss of zonal isolation can lead to contamination of overlying aquifers or loss of hydrocarbon resources. Gas migration into shallow formations or accumulation to significant pressure under a wellhead could create a health and safety hazard.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.29)
- North America > Canada > Alberta (0.28)
Abstract Monitoring of CO2 plumes is required to verify long-term sequestration of injected CO2, detect possible leaks from the storage zone, and infer deviations in plume path due to unforeseen large-scale geologic anomalies like flow barriers or high permeability streaks. Although several alternatives are available for monitoring plume path deviations during injection, the cost of monitoring still is a paramount concern for operators. The conjecture of this work is that dynamic data measured at injection wells are informative of the presence of heterogeneities large enough to affect plume paths. Hence geologic models updated using injection data can be used to predict better the trajectory of CO2 plumes and to design operational schemes that will ensure long term containment of the injected CO2. To test this conjecture, we have adapted a probabilistic history matching software (Pro-HMS) originally developed for oil field applications. The software assimilates injection data commonly monitored at active and inactive wells into models for the subsurface aquifer/reservoir. The algorithm yields an ensemble of realizations geologically consistent with the initial model such that the uncertainty in CO2 plume location can be easily assessed. We illustrate the approach with synthetic examples (a deep, heterogeneous aquifer with a long streak of large or small permeability) for which the reference bottomhole pressure and rate responses from injection and inactive wells were obtained from simulation. The updated models obtained after the history matching process detected the presence of the streak, and the subsequent estimation of CO2 plume location was much more accurate. Pressure data recorded at inactive wells were essential for detecting the streak. Monitoring such wells is thus expected to provide valuable information about geologic heterogeneities. The results confirm that injection rate and pressure data provide an inexpensive option for monitoring CO2 plumes. Introduction Monitoring the progress of CO2 plumes in a geologic sequestration process is crucial to ensure that the process is safe and the confinement effective (Benson, 2006). The International Governmental Panel on Climate Change (Holloway et al., 2006) recommended "to model the injection of CO2 into storage reservoir and future behavior, monitor the storage system and use the monitoring results to validate and update the model", but this guideline is not specific about the monitoring technique to be used. Many alternatives for CO2 monitoring have been proposed in the literature such as time-lapse seismic (Gouping, 2003; Torp and Gale, 2004), gravity measurements (Nooner et al., 2007), well logging (Yamaguchi et al., 2006) and surface deformation via satellite imaging (Mathieson et al., 2009). The choice of technique depends on the objectives for monitoring. For instance, geologic engineers who are interested in model updating might opt for injection pressure history matching combined with 4D seismic data integration, wheareas environmental engineers might choose geochemical sampling or gas surveys for leak detection. Benson (2006) summarized the advantages, limitations and drawbacks of current monitoring techniques taking into consideration the monitoring objectives and the geologic characteristics of the storage formation. Utilizing reservoir pressure data for monitoring the progress of the CO2 plume is one of the cheapest alternatives since it can be carried out with injection pressure and/or rate data that are routinely acquired during normal operation. Large-scale heterogeneities such as faults, high permeability streaks and fractures can lead to plume migration out of the target reservoir (Ambrose et al., 2008). Permeability barriers or faults can cause excessive pressure buildup, resulting in limited injectivity and increased risk of failure (Oruganti and Bryant, 2009). The increase in pore pressure during injection can also activate faults or open fractures, leading to re-orientation of the CO2 plume.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Utsira Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Egersund Basin > PL 038 > Sleipner Formation (0.93)
Abstract When CO2 is injected in deep saline aquifers on the scale of gigatonnes, pressure buildup in the aquifer during injection will be a critical issue. Because fracturing, fault activation and leakage of brine along pathways such as abandoned wells require a threshold pressure (Nicot et al., 2009), operators and regulators will be concerned with a critical contour of overpressure (CoP). The extent of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence of faults, abandoned wells etc.). The extent also depends on relative permeability, and from the three-region injection model (Burton et al., 2008), we derive analytical expressions for a specific contour of overpressure at any given time. The risk of pressure-induced leakage from the aquifer can therefore be understood in terms of phase mobilities and speeds of saturation fronts. This provides a quick tool for estimating pressure profiles. Seven different relative permeability curves (Bennion and Bachu, 2005) and their effect on the CoPs in each of the three regions have been studied. The relative permeability curve which gives the maximum two-phase region mobility (MBL) gives the lowest pressure buildup (specific CoP is closest to the injector). Thus characterizing relative permeability will be an important consideration for the practical implementation of CO2 storage projects. For smaller values of critical CoP which lie in the brine region, the location of the critical CoP, and hence the risk due to pressure buildup, are time-invariant and independent of relative permeability. This result significantly reduces the uncertainty in predicting these contours of overpressure. Introduction Geologic sequestration of CO2 is widely regarded as one of the viable options for GHG mitigation. Because sequestration must be conducted at a very large scale, the safety and effectiveness of storage schemes will be important. To date, regulatory frameworks have focused on risks associated with the extent of the CO2 plume. But injection of such large volumes of CO2 into deep saline aquifers over a time span of a few decades also leads to significant pressure buildup. This "pressure plume" extends much farther than the CO2 plume. The risks associated with excessive overpressure in the aquifer include mechanical damage to the storage formation, fracturing the seal of the storage formation, opening faults or fractures, and displacement of brine into underground sources of drinking water (USDW). Each of these phenomena involves a threshold pressure (see Nicot et al. (2009) for analysis of brine displacement through abandoned wells). Thus a convenient proxy for these risks is the contour of critical overpressure (CoP). The critical overpressure is the minimum increment in aquifer pore pressure that would cause any of the negative impacts mentioned above (brine leakage, mechanical damage). The CoP thus depends strongly on properties of the target aquifer. For this study, we illustrate the behavior with several arbitrary values of critical overpressure.
- North America > United States > Texas (0.28)
- North America > Canada > Alberta (0.28)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
Abstract We rigorously model immiscible displacements in unconsolidated sediments subject to confining stress. Fluid-fluid interfaces are assumed controlled by capillary forces, and the progressive quasi-static (PQS) algorithm based on the level set method determines the pore level geometry of those interfaces. From the pore-level fluid configuration we compute the net force exerted on each sediment grain by capillary pressure, including cohesion at grain contacts supporting pendular rings. We combine those forces with mechanical stress and elastic properties of grains to determine the resultant movement of grains using a discrete element method code (Itasca's PFC3D). To our knowledge this is the first rigorous coupling of capillarity and grain solid mechanics in 3D. When grains can move in response to net force exerted by the nonwetting phase, small variations in the distribution of pore throat sizes lead to self-reinforcing, focused channels of nonwetting phase during drainage. When forces exerted by capillary pressure are the same magnitude as the force required to displace grains, this channeling prevents the emergence of a recognizable fracture. 1. Introduction The migration of gas through water-saturated soft sediment is an important aspect of fluid dynamics under the seafloor in several parts of the world (Collett et al 1999). A model for this process would be useful for assessing the competition between drainage (controlled by capillary forces) and fracturing (controlled by pore pressure and earth stresses). This competition governs the evolution of natural gas seeps, the formation of methane hydrates and many schemes to produce gas from hydrates, and the viability of carbon sequestration in sub-seafloor sediments. When gas invades an unconsolidated, weakly confined, water-saturated sediment, the large-scale behavior ranges between two limiting cases. One is fracturing of the sediment with emplacement of gas limited to the volume of the fracture. The other is drainage of the pore space and broadly distributed emplacement of gas at large saturation. The large-scale behavior emerges from grain-scale competition between capillarity-controlled movement of the gas/water meniscus and pore-pressure controlled displacement of the grains. The competition is primarily influenced by the grain size: Capillary invasion happens in coarse grained sediments while fracturing is dominant in fine grained (Jain and Juanes 2009, Behseresht et al. 2008). The cited work provides a consistent, semi-quantitative picture of behavior, but relies on several restrictions or simplifications of the physics, such as 2D grain mechanics or a purely kinematic grain displacement model (see also Prodanovic and Bryant, 2008b). This paper builds on this work with the goal of verifying our previous insights. We have particular interest in the behavior at intermediate grain sizes, when the pressures required for drainage and for fracturing are comparable. Previous investigation with kinematic models indicates that if sediment grains are randomly arranged and movable, gas invasion forms channels (Prodanovic and Bryant, 2008b). If sediment grains are (locally) ordered and movable, gas invasion form fracture-like patterns oriented by the original ordering. If the grains in the sediment are randomly arranged and fixed, gas invasion forms a highly ramified structure corresponding to classical drainage.
- North America > Canada (0.68)
- North America > United States > Texas (0.46)