HIERARCHICAL STATE ESTIMATION FOR WIDE AREA POWER SYSTEMS

This thesis presents the application of hierarchical state estimation techniques to consolidate the state output of a wide area power system network. In a wide area network a large number of interconnections exist between various utilities of the wide area. Power transactions between areas occur over large distances and hence for better security there is a need to monitor the state of the entire wide area systems. Hierarchical state estimation is preferred over integrated state estimation, due to the reduced computational time. Using existing state estimators of the member utilities of the wide area in the bottom level of hierarchical state estimation proves to be economical. The coordination level alone needs to be done using the state estimation output of the member areas for obtaining the overall state estimate. In this thesis a modified coordination technique derived from hierarchical state estimation is proposed to consolidate the state outputs of all the individual entities in the wide area. Issues due to heterogeneity of the estimators in each member utility of the wide area have been identified and addressed. A modification to the traditional hierarchical state estimation approach has been proposed which overcomes issues of delay and loss of state outputs from the estimators in the wide area. Use of synchronized phasor measurements in the hierarchical structure has been studied. The coordination algorithms have been tested on an IEEE 118 bus system by splitting the system into smaller areas. The results of the algorithms have been analyzed on the basis of accuracy and speed. The results of these algorithms have been compared to integrated state estimation of the wide area. The results show that the coordination algorithm is four times faster than the integrated state estimator without sacrificing the level of accuracy. To account for the issues regarding the delay of state output arrivals and the absence of state outputs from an area, the coordination algorithm of the hierarchical state estimation technique has been modified. As might be expected, the modified coordination algorithm decreases the accuracy of the overall state estimate. In contrast, the use of synchronized phasor measurements in all the levels of the hierarchical state estimator increases the confidence of the overall estimate apart from increasing the performance of the estimation process

Development of Science-Based Permitting Guidance for Geological Sequestration of CO2 in Deep Saline Aquifers Based on Modeling and Risk Assessment

Underground carbon storage may become one of the solutions to address global warming. However, to have an impact, carbon storage must be done at a much larger scale than current CO{sub 2} injection operations for enhanced oil recovery. It must also include injection into saline aquifers. An important characteristic of CO{sub 2} is its strong buoyancy--storage must be guaranteed to be sufficiently permanent to satisfy the very reason that CO{sub 2} is injected. This long-term aspect (hundreds to thousands of years) is not currently captured in legislation, even if the U.S. has a relatively well-developed regulatory framework to handle carbon storage, especially in the operational short term. This report proposes a hierarchical approach to permitting in which the State/Federal Government is responsible for developing regional assessments, ranking potential sites (''General Permit'') and lessening the applicant's burden if the general area of the chosen site has been ranked more favorably. The general permit would involve determining in the regional sense structural (closed structures), stratigraphic (heterogeneity), and petrophysical (flow parameters such as residual saturation) controls on the long-term fate of geologically sequestered CO{sub 2}. The state-sponsored regional studies and the subsequent local study performed by the applicant will address the long-term risk of the particular site. It is felt that a performance-based approach rather than a prescriptive approach is the most appropriate framework in which to address public concerns. However, operational issues for each well (equivalent to the current underground injection control-UIC-program) could follow regulations currently in place. Area ranking will include an understanding of trapping modes. Capillary (due to residual saturation) and structural (due to local geological configuration) trappings are two of the four mechanisms (the other two are solubility and mineral trappings), which are the most relevant to the time scale of interest. The most likely pathways for leakage, if any, are wells and faults. We favor a defense-in-depth approach, in which storage permanence does not rely upon a primary seal only but assumes that any leak can be contained by geologic processes before impacting mineral resources, fresh ground water, or ground surface. We examined the Texas Gulf Coast as an example of an attractive target for carbon storage. Stacked sand-shale layers provide large potential storage volumes and defense-in-depth leakage protection. In the Texas Gulf Coast, the best way to achieve this goal is to establish the primary injection level below the total depth of most wells (>2,400 m-8,000 ft). In addition, most faults, particularly growth faults, present at the primary injection level do not reach the surface. A potential methodology, which includes an integrated approach comprising the whole chain of potential events from leakage from the primary site to atmospheric impacts, is also presented. It could be followed by the State/Federal Government, as well as by the operators

Study of the flow of and deposition from turbidity currents

textChemical Engineerin

Characterization of Turbiditic Oil Reservoirs Based on Geophysical Models of Their Formation

Two aspects of the characterization of turbiditic oil reservoirs based on geophysical models of their formation are discussed in this report. First, we have developed a new, more accurate and computationally faster finite-element method (FEM) for simulating the flow and deposition of turbidity currents. Although a finite volume method had been presented and discussed in a previous report, it was discovered to be insufficient for our purposes of simulating turbidity flows. The new method allows variable grids near the regions of large deposition, which are of most interest, and numerically results in banded, sparse matrices that are much faster to solve. Examples of the success of the method are presented. In the second part of this report, we present and discuss a preliminary study on the feasibility of matching the results of a sediment transport model to field data. With the simulation of the turbidity current we can create an entire turbiditic deposit. This requires the initial conditions of the flow, such as the amount of sediment, the volume or flow rate of the current, etc, which are of course unavailable. This requires an estimate of the initial conditions of the flow, which can be determined from limited data from the deposit. We used the Excel optimization routine Solver to reproduce a one-dimensional algebraically simulated deposit with and without measurement noise. Results indicate that such matching is feasible, provided that the noise is below certain thresholds, dependent on the size of the deposit and the number data points constraining the parameter estimation

CHARACTERIZATION OF TURBIDITIC OIL RESERVOIRS BASED ON GEOPHYSICAL MODELS OF THEIR FORMATION

Two aspects of the characterization of turbiditic oil reservoirs based on geophysical models of their formation are discussed in this report. First, we have developed a new, more accurate and computationally faster finite-element method (FEM) for simulating the flow and deposition of turbidity currents. Although a finite volume method had been presented and discussed in a previous report, it was discovered to be insufficient for our purposes of simulating turbidity flows. The new method allows variable grids near the regions of large deposition, which are of most interest, and numerically results in banded, sparse matrices that are much faster to solve. Examples of the success of the method are presented. In the second part of this report, we present and discuss a preliminary study on the feasibility of matching the results of a sediment transport model to field data. With the simulation of the turbidity current we can create an entire turbiditic deposit. This requires the initial conditions of the flow, such as the amount of sediment, the volume or flow rate of the current, etc, which are of course unavailable. This requires an estimate of the initial conditions of the flow, which can be determined from limited data from the deposit. We used the Excel optimization routine Solver to reproduce a one-dimensional algebraically simulated deposit with and without measurement noise. Results indicate that such matching is feasible, provided that the noise is below certain thresholds, dependent on the size of the deposit and the number data points constraining the parameter estimation

Source-Sink Matching and Potential for Carbon Capture and Storage in the Gulf Coast

Current global levels of anthropogenic CO2 emissions are 25.6 Gigatons yr. Approximately 1 Gigaton comes from the Texas, Louisiana, and Mississippi Gulf Coast, representing 16 percent of the U.S. annual CO2 emissions from fossil fuels. The Gulf Coast region provides an opportunity for addressing the problem. Geologic sequestration results from the capturing of CO2 from combustion products and injecting the compressed gas as a supercritical fluid into subsurface brine aquifers for long-term storage. The Gulf Coast overlies an unusually thick succession of highly porous and permeable sand aquifers separated by thick shale aquitards. The Gulf Coast also has a large potential for enhanced oil recovery (EOR), in which CO2 injected into suitable oil reservoirs could be used first for EOR and then for large-volume, long-term storage of CO2 in nonproductive formations below the reservoir interval. For example, there are numerous opportunities for locating CO2 injection wells either in fields for EOR or in stacked brine aquifers near potential FutureGen sites, where a near-zero emission facility would generate primarily hydrogen and CO2 as by-products. We estimate that in the Gulf Coast, outside of the traditional area of CO2 EOR in the Permian Basin, an additional 4.5 billion barrels of oil could be produced by using miscible CO2. At $60 per barrel, this incremental production is estimated to have a wellhead value of$270 billion that could generate more than $40 billion in taxes.Bureau of Economic Geolog