Browsing by Subject "CO2 sequestration"
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Item Experimental and simulation studies of sequestration of supercritical carbon dioxide in depleted gas reservoirs(Texas A&M University, 2004-09-30) Seo, Jeong Gyuhe feasibility of sequestering supercritical CO2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside an aluminum coreholder that is then evacuated. Second, with or without connate water, the carbonate core is saturated with methane. Third, supercritical CO2 is injected into the core with 300 psi overburden pressure. From the volume and composition of the produced gas measured by a wet test meter and a gas chromatograph, the recovery of methane at CO2 breakthrough is determined. The core is scanned three times during an experimental run to determine core porosity and fluid saturation profile: at start of the run, at CO2 breakthrough, and at the end of the run. Runs were made with various temperatures, 20?C (68?F) to 80?C (176?F), while the cell pressure is varied, from 500 psig (3.55 MPa) to 3000 psig (20.79 MPa) for each temperature. An analytical study of the experimental results has been also conducted to determine the dispersion coefficient of CO2 using the convection-dispersion equation. The dispersion coefficient of CO2 in methane is found to be relatively low, 0.01-0.3 cm2/min.. Based on experimental and analytical results, a 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO2 under typical field conditions. The depleted gas reservoir is repressurized by CO2 injection from 500 psi to its initial pressure 3,045 psi. Simulation results for 400 bbl/d CO2 injection may be summarized as follows. First, a large amount of CO2 is sequestered: (i) about 1.2 million tons in 29 years (0 % initial water saturation) to 0.78 million tons in 19 years (35 % initial water saturation) for 40-acre pattern, (ii) about 4.8 million tons in 112 years (0 % initial water saturation) to 3.1 million tons in 73 years (35 % initial water saturation) for 80-acre pattern. Second, a significant amount of natural gas is also produced: (i) about 1.2 BSCF or 74 % remaining GIP (0 % initial water saturation) to 0.78 BSCF or 66 % remaining GIP (35 % initial water saturation) for 40-acre pattern, (ii) about 4.5 BSCF or 64 % remaining GIP (0 % initial water saturation) to 2.97 BSCF or 62 % remaining GIP (35 % initial water saturation) for 80-acre pattern. This produced gas revenue could help defray the cost of CO2 sequestration. In short, CO2 sequestration in depleted gas reservoirs appears to be a win-win technology.Item Geologic drivers affecting buoyant plume migration patterns in small-scale heterogeneous media : characterizing capillary channels of sequestered CO₂(2012-12) Ravi Ganesh, Priya; Bryant, Steven L.; Meckel, Timothy AshworthCO₂ sequestration aims for the most efficient utilization of reservoir pore volume and for maximizing security of storage. For typical field conditions and injection rates, buoyancy and capillary forces grow dominant over viscous forces within hundreds of meters of the injection wells as the pressure gradient from injection becomes less influential on flow processes. Flow regimes ranging from compact flow to capillary channel flow or secondary accumulation beneath a seal are possible through time as the CO₂ plume travels through the storage reservoir. Here we model the range of possible migration behavior in the capillary channel regime in small-scale domains whose heterogeneity has been resolved at depositional (sub-millimeter) scale. Two types of model domains have been studied in this work: domains with depositional fabric from real, naturally-occurring geologic samples and geostatistically generated synthetic model fabrics. The real domains come from quasi-2D physical geologic samples (peel # 1: ~1 m × 0.5 m sample and peel # 2: ~0.4 m × 0.6 m sample) that are vertically oriented relief peels of fluvial sediment extracted from the Brazos River, Texas. Peel # 1 is oriented perpendicular to dominant depositional flow while peel # 2 is a flow-parallel specimen. The various depositional fabrics represent definite correlation lengths of threshold pressures in the horizontal and vertical directions which can be extracted. High-resolution (~2 million element model) laser scanning of the samples provided detailed topography which is the result of nearly linear corresponding changes in measured grain size (normal distribution) and sorting. We model the basic physics of buoyant migration in heterogeneous domain using commercial software which applies the principle of invasion percolation (IP). The criterion for governing drainage at the pore scale is that the capillary pressure of the fluid needs to be greater than or equal to the threshold pressure of the pore throat it is trying to enter for the interface to advance into the pore. Here we employ the extension of this concept to flows at larger scales, which replaces the pore throat with a volume of rock with a characteristic value of capillary entry pressure. The fluid capillary pressure is proportional to the height of continuous column of the buoyant phase. The effects of (i) threshold pressure range, i.e. difference between the maximum and minimum threshold pressures in the domain; and (ii) the density difference between CO₂ and connate water on capillary channels of CO₂ were studied on the various sedimentologic fabrics. As the rock and fluid properties varied for different model domains, ₂ migration patterns varied between predominantly fingering and predominantly back-filling structures. Sufficiently heterogeneous media (threshold pressures varying by a factor of 10 or more) and media with depositional fabrics having high ratios of horizontal and vertical correlation lengths of capillary entry pressures in the domain yield back-filling pattern, resulting in a significantly large storage capacity. Invasion percolation simulation models give qualitatively similar CO₂ migration patterns compared to full-physics simulators in small-scale but high resolution domains which are sufficiently heterogeneous. On the other hand, we find the invasion percolation simulations predicting disperse capillary fingering pattern in relatively homogeneous media (threshold pressures varying by less than a factor of 10) while the full-physics simulations reveal a very compact CO₂ front in the same media. This stark difference needs to be investigated to understand the governing flow physics in these domains. Fingering flow pattern in the capillary channel regime would clearly result in the estimated storage capacity being much less than the nominal value (the pore volume of the rock) as the rock-fluid contact is minimal. The importance of this work lies in the verification that a relatively simple model (invasion percolation), which runs in a very small fraction of the time required by full-physics simulators, can be used to study buoyant migration in rocks at the micro-scale. Understanding migration behavior at the small-scale can help us approach the problem of upscaling better and hence define the complex plume dynamics at the reservoir scale more realistically. Knowledge of the correlation structure of the sedimentologic fabric (ratio of correlation lengths of threshold pressures in horizontal and vertical directions) and the threshold pressure distribution (permeability distribution) for any given reservoir rock could help evaluate amount of CO₂ that can be stored per unit volume of rock (storage potential) for a reservoir in the migration phase of sequestration. The possibility of predictive ability for expected capillary channel flow patterns kindles the prospect of enabling an engineered storage strategy that drives the behavior toward the desired flow patterns in the subsurface.Item Influence of Rock Types on Seismic Monitoring of CO2 Sequestration in Carbonate Reservoirs(2012-10-19) Mammadova, ElnaraAlthough carbonates hold more than 60 percent of the world's oil reserves, they, nevertheless, exhibit much lower average recovery factor values than terrigenous sandstone reservoirs. Thus, utilization of advanced enhanced oil recovery (EOR) techniques such as high pressure CO2 injection may normally be required to recover oil in place in carbonate reservoirs. This study addresses how different rock types can influence the seismic monitoring of CO2 sequestration in carbonates. This research utilizes an elastic parameter, defined in a rock physics model of poroelasticity and so-?called as the frame flexibility factor, to successfully quantify the carbonate pore types in core samples available from the Great Bahama Bank (GBB). This study shows that for carbonate samples of a given porosity the lower the frame flexibility factors the higher is the sonic wave velocity. Generally, samples with frame flexibility values of <4 are either rocks with visible moldic pores or intraframe porosity; whereas, samples with frame flexibility values of >4 are rocks with intercrystalline and microporosity. Hence, different carbonate pore geometries can be quantitatively predicted using the elastic parameters capable of characterizing the porous media with a representation of their internal structure on the basis of the flexibility of the frame and pore connectivity. In this research, different fluid substitution scenarios of liquid and gaseous CO2 saturations are demonstrated to characterize the variations in velocity for carbonate-specific pore types. The results suggest that the elastic response of CO2 flooded rocks is mostly governed by pore pressure conditions and carbonate rock types. Ultrasonic P-?wave velocities in the liquid-?phase CO2 flooded samples show a marked decrease in the order of 0.6 to 16 percent. On the contrary, samples flooded with gaseous-?phase CO2 constitute an increase in P-?wave velocities for moldic and intraframe porosities, while establishing a significant decrease for samples with intercrystalline and micro-?porosities. Such velocity variations are explained by the stronger effect of density versus compressibility, accounting for the profound effect of pore geometries on the acoustic properties in carbonates. The theoretical results from this research could be a useful guide for interpreting the response of time-?lapse seismic monitoring of carbonate formations following CO2 injection at depth. In particular, an effective rock-?physics model can aid in better discrimination of the profound effects of different pore geometries on seismic monitoring of CO2 sequestration in carbonates.Item Kinetics of CO₂ dissolution in brine : experimental measurement and application to geologic storage(2012-05) Blyton, Christopher Allen Johnson; Bryant, Steven L.; Lake, Larry W.A novel approach to geologic CO₂ sequestration is the surface dissolution method. This method involves lifting native brine from an aquifer, dissolution of CO₂ into the brine using pressurized mixing and injection of the CO₂ saturated brine back into the aquifer. This approach has several advantages over the conventional approach, including minimization of the risk of buoyancy driven leakage and dramatic reduction in the extent of pressure elevation in the storage structure. The mass transfer coefficient for the CO₂/brine two-phase system and associated transport calculations allow efficient design of the surface equipment required to dissolve CO₂ under pressure. This data was not previously available in the literature. Original experimental data on the rate of dissolution of CO₂ into Na-Ca-Cl brines across a range of temperatures and wet CO₂ densities are presented. From this data, the intrinsic mass transfer coefficient between CO₂-rich and aqueous phases has been calculated. The statistically significant variation in the mass transfer coefficient was evaluated and compared with the variation caused by the experimental method. An empirical correlation was developed that demonstrates that the mass transfer coefficient is a function of the NaCl salinity, temperature and wet CO₂ density. For the conditions tested, the value of the coefficient is in the range of 0.015 to 0.056 cm/s. Greater temperature and smaller NaCl salinity increases the mass transfer coefficient. There is an interaction effect between temperature and wet CO₂ density, which increases or decreases the mass transfer coefficient depending on the value of each. CaCl₂ salinity does not have a statistically significant effect on the mass transfer coefficient. The transport calculations demonstrate that wellhead co-injection of CO₂ and brine is feasible, providing the same technical outcome at lower cost. For example, assuming a 2000 ft deep well and typical aquifer injection conditions, complete dissolution of the bulk COv phase can be achieved at 670 ft for bubbles of 0.16 cm initial radius. Using a horizontal pipe or mixing tank was also shown to be feasible. Gas entrainment was shown to provide a marked reduction in size of mixing apparatus required.Item Predicting the migration of CO₂ plume in saline aquifers using probabilistic history matching approaches(2012-05) Bhowmik, Sayantan; Srinivasan, Sanjay; Bryant, Steven L.During the operation of a geological carbon storage project, verifying that the CO₂ plume remains within the permitted zone is of particular interest both to regulators and to operators. However, the cost of many monitoring technologies, such as time-lapse seismic, limits their application. For adequate predictions of plume migration, proper representation of heterogeneous permeability fields is imperative. Previous work has shown that injection data (pressures, rates) from wells might provide a means of characterizing complex permeability fields in saline aquifers. Thus, given that injection data are readily available and inexpensive, they might provide an inexpensive alternative for monitoring; combined with a flow model like the one developed in this work, these data could even be used for predicting plume migration. These predictions of plume migration pathways can then be compared to field observations like time-lapse seismic or satellite measurements of surface-deformation, to ensure the containment of the injected CO₂ within the storage area. In this work, two novel methods for creating heterogeneous permeability fields constrained by injection data are demonstrated. The first method is an implementation of a probabilistic history matching algorithm to create models of the aquifer for predicting the movement of the CO₂ plume. The geologic property of interest, for example hydraulic conductivity, is updated conditioned to geological information and injection pressures. The resultant aquifer model which is geologically consistent can be used to reliably predict the movement of the CO₂ plume in the subsurface. The second method is a model selection algorithm that refines an initial suite of subsurface models representing the prior uncertainty to create a posterior set of subsurface models that reflect injection performance consistent with that observed. Such posterior models can be used to represent uncertainty in the future migration of the CO₂ plume. The applicability of both methods is demonstrated using a field data set from central Algeria.Item Reservoir simulation of co2 sequestration and enhanced oil recovery in Tensleep Formation, Teapot Dome field(Texas A&M University, 2006-04-12) Gaviria Garcia, RicardoTeapot Dome field is located 35 miles north of Casper, Wyoming in Natrona County. This field has been selected by the U.S. Department of Energy to implement a field-size CO2 storage project. With a projected storage of 2.6 million tons of carbon dioxide a year under fully operational conditions in 2006, the multiple-partner Teapot Dome project could be one of the world's largest CO2 storage sites. CO2 injection has been used for decades to improve oil recovery from depleted hydrocarbon reservoirs. In the CO2 sequestration technique, the aim is to "co-optimize" CO2 storage and oil recovery. In order to achieve the goal of CO2 sequestration, this study uses reservoir simulation to predict the amount of CO2 that can be stored in the Tensleep Formation and the amount of oil that can be produced as a side benefit of CO2 injection. This research discusses the effects of using different reservoir fluid models from EOS regression and fracture permeability in dual porosity models on enhanced oil recovery and CO2 storage in the Tensleep Formation. Oil and gas production behavior obtained from the fluid models were completely different. Fully compositional and pseudo-miscible black oil fluid models were tested in a quarter of a five spot pattern. Compositional fluid model is more convenient for enhanced oil recovery evaluation. Detailed reservoir characterization was performed to represent the complex characteristics of the reservoir. A 3D black oil reservoir simulation model was used to evaluate the effects of fractures in reservoir fluids production. Single porosity simulation model results were compared with those from the dual porosity model. Based on the results obtained from each simulation model, it has been concluded that the pseudo-miscible model can not be used to represent the CO2 injection process in Teapot Dome. Dual porosity models with variable fracture permeability provided a better reproduction of oil and water rates in the highly fractured Tensleep Formation.Item Time-lapse seismic monitoring of subsurface fluid flow(Texas A&M University, 2004-09-30) Yuh, Sung H.Time-lapse seismic monitoring repeats 3D seismic imaging over a reservoir to map fluid movements in a reservoir. During hydrocarbon production, the fluid saturation, pressure, and temperature of a reservoir change, thereby altering the acoustic properties of the reservoir. Time-lapse seismic analysis can illuminate these dynamic changes of reservoir properties, and therefore has strong potential for improving reservoir management. However, the response of a reservoir depends on many parameters and can be diffcult to understand and predict. Numerical modeling results integrating streamline fluid flow simulation, rock physics, and ray-Born seismic modeling address some of these problems. Calculations show that the sensitivity of amplitude changes to porosity depend on the type of sediment comprising the reservoir. For consolidated rock, high-porosity models show larger amplitude changes than low porosity models. However, in an unconsolidated formation, there is less consistent correlation between amplitude and porosity. The rapid time-lapse modeling schemes also allow statistical analysis of the uncertainty in seismic response associated with poorly known values of reservoir parameters such as permeability and dry bulk modulus. Results show that for permeability, the maximum uncertainties in time-lapse seismic signals occur at the water front, where saturation is most variable. For the dry bulk-modulus, the uncertainty is greatest near the injection well, where the maximum saturation changes occur. Time-lapse seismic methods can also be applied to monitor CO2 sequestration. Simulations show that since the acoustic properties of CO2 are very different from those of hydrocarbons and water, it is possible to image CO2 saturation using seismic monitoring. Furthermore, amplitude changes after supercritical fluid CO2 injection are larger than liquid CO2 injection. Two seismic surveys over Teal South Field, Eugene Island, Gulf of Mexico, were acquired at different times, and the numerical models provide important insights to understand changes in the reservoir. 4D seismic differences after cross-equalization show that amplitude dimming occurs in the northeast and brightening occurs in the southwest part of the field. Our forward model, which integrates production data, petrophysicals, and seismic wave propagation simulation, shows that the amplitude dimming and brightening can be explained by pore pressure drops and gas invasion, respectively.