Relevant bibliographies by topics / Storage reservoir

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  2. Dissertations / Theses
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Academic literature on the topic 'Storage reservoir'

Author: Grafiati
Published: 4 June 2021
Last updated: 4 February 2022

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Journal articles on the topic "Storage reservoir"

1

Fitriana, Indri Rahmandhani, Djoko Legono, and Heriantono Waluyadi. "Reservoir sedimentation regime analysis: case study of Kedungombo reservoir and Sermo reservoir." MEDIA KOMUNIKASI TEKNIK SIPIL 27, no. 1 (August 20, 2021): 80–87. http://dx.doi.org/10.14710/mkts.v27i1.35978.

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The Kedungombo and the Sermo Reservoirs have problems in fulfilling basic services because of sedimentation. Sedimentation that occurs in each of the reservoirs would form a specific reservoir sedimentation pattern that is supposed to be similar because the hydrology and physiography conditions of the reservoir's catchment area are similar. This study aims to determine the dynamics of sedimentation patterns that occur in the dead storage for reviewing the characteristics/sedimentation regime of the two reservoirs. The analysis was carried out by processing bathymetrical data which were processed into a digital terrain model (DTM) using ArcGIS. Furthermore, the storage volume, sedimentation volume, storage percentage, and specific reservoir sedimentation rate are calculated. The results showed that the two reservoirs showed an increase in sedimentation volume each year so that the reservoir characteristic curve shifted from the plan graph. The dead storage capacity of Kedungombo Reservoir is 100% in 1989 to 43% in 2016 and 100% of Sermo Reservoir in 1997 to 58% in 2011. The specific reservoir sedimentation rate, i.e. 0.0031 and 0.0042 million m3/year/km2 for the Kedungombo Reservoir (between 1989 and 2016) and the Sermo Reservoir (between 1997 and 2011) respectively, indicating that the two reservoirs are in the same regime
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2

Zhou, Tian, Bart Nijssen, Huilin Gao, and Dennis P. Lettenmaier. "The Contribution of Reservoirs to Global Land Surface Water Storage Variations*." Journal of Hydrometeorology 17, no. 1 (December 21, 2015): 309–25. http://dx.doi.org/10.1175/jhm-d-15-0002.1.

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Abstract Man-made reservoirs play a key role in the terrestrial water system. They alter water fluxes at the land surface and impact surface water storage through water management regulations for diverse purposes such as irrigation, municipal water supply, hydropower generation, and flood control. Although most developed countries have established sophisticated observing systems for many variables in the land surface water cycle, long-term and consistent records of reservoir storage are much more limited and not always shared. Furthermore, most land surface hydrological models do not represent the effects of water management activities. Here, the contribution of reservoirs to seasonal water storage variations is investigated using a large-scale water management model to simulate the effects of reservoir management at basin and continental scales. The model was run from 1948 to 2010 at a spatial resolution of 0.25° latitude–longitude. A total of 166 of the largest reservoirs in the world with a total capacity of about 3900 km3 (nearly 60% of the globally integrated reservoir capacity) were simulated. The global reservoir storage time series reflects the massive expansion of global reservoir capacity; over 30 000 reservoirs have been constructed during the past half century, with a mean absolute interannual storage variation of 89 km3. The results indicate that the average reservoir-induced seasonal storage variation is nearly 700 km3 or about 10% of the global reservoir storage. For some river basins, such as the Yellow River, seasonal reservoir storage variations can be as large as 72% of combined snow water equivalent and soil moisture storage.
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3

Mu, Mengfei, Qiuhong Tang, Songjun Han, Xiaomang Liu, and Huijuan Cui. "Using GRanD Database and Surface Water Data to Constrain Area–Storage Curve of Reservoirs." Water 12, no. 5 (April 27, 2020): 1242. http://dx.doi.org/10.3390/w12051242.

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Basic information on global reservoirs is well documented in databases such as GRanD (Global Reservoir and Dam) and ICOLD (International Commission on Large Dams). However, though playing a critical role in estimating reservoir storage variations from remote sensing or hydrological models, area–storage curves of reservoirs are not conveniently obtained nor publicly shared. In this paper, we combine the GRanD database and Landsat-based global surface water extent (GSW) data to derive area–storage curves of reservoirs. The reported storage capacity in the GRanD database and water surface area from GSW data were used to constrain the area–storage curve. The proposed method has the potential to derive area–storage curves of reservoirs larger than 1 km2 archived in the GRanD database. The derived curves are validated with in situ reservoir data collected in US and China, and the results show that in situ records are well captured by the derived curves both in large and small reservoirs with various shapes. The derived area–storage curves could be employed to advance global monitoring or modeling of reservoir storage dynamics.
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4

Longuevergne, L., C. R. Wilson, B. R. Scanlon, and J. F. Crétaux. "GRACE water storage estimates for the Middle East and other regions with significant reservoir and lake storage." Hydrology and Earth System Sciences 17, no. 12 (December 5, 2013): 4817–30. http://dx.doi.org/10.5194/hess-17-4817-2013.

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Abstract. While GRACE (Gravity Recovery and Climate Experiment) satellites are increasingly being used to monitor total water storage (TWS) changes globally, the impact of spatial distribution of water storage within a basin is generally ignored but may be substantial. In many basins, water is often stored in reservoirs or lakes, flooded areas, small aquifer systems, and other localized regions with areas typically below GRACE resolution (~200 000 km2). The objective of this study was to assess the impact of nonuniform water storage distribution on GRACE estimates of TWS changes as basin-wide averages, focusing on surface water reservoirs and using a priori information on reservoir storage from radar altimetry. Analysis included numerical experiments testing effects of location and areal extent of the localized mass (reservoirs) within a basin on basin-wide average water storage changes, and application to the lower Nile (Lake Nasser) and Tigris–Euphrates basins as examples. Numerical experiments show that by assuming uniform mass distribution, GRACE estimates may under- or overestimate basin-wide average water storage by up to a factor of ~2, depending on reservoir location and areal extent. Although reservoirs generally cover less than 1% of the basin area, and their spatial extent may be unresolved by GRACE, reservoir storage may dominate water storage changes in some basins. For example, reservoir storage accounts for ~95% of seasonal water storage changes in the lower Nile and 10% in the Tigris–Euphrates. Because reservoirs are used to mitigate droughts and buffer against climate extremes, their influence on interannual timescales can be large. For example, TWS decline during the 2007–2009 drought in the Tigris–Euphrates basin measured by GRACE was ~93 km3. Actual reservoir storage from satellite altimetry was limited to 27 km3, but their apparent impact on GRACE reached 45 km3, i.e., 50% of GRACE trend. Therefore, the actual impact of reservoirs would have been greatly underestimated (27 km3) if reservoir storage changes were assumed uniform in the basin. Consequently, estimated groundwater contribution from GRACE would have been largely overestimated in this region if the actual distribution of water was not explicitly taken into account. Effects of point masses on GRACE estimates are not easily accounted for via simple multiplicative scaling, but in many cases independent information may be available to improve estimates. Accurate estimation of the reservoir contribution is critical, especially when separating estimating groundwater storage changes from GRACE total water storage (TWS) changes. Because the influence of spatially concentrated water storage – and more generally water distribution – is significant, GRACE estimates will be improved by combining independent water mass spatial distribution information with GRACE observations, even when reservoir storage is not the dominant mechanism. In this regard, data from the upcoming Surface Water Ocean Topography (SWOT) satellite mission should be an especially important companion to GRACE-FO (Follow-On) observations.
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Asfaw, Tilahun Derib, Khamaruzaman Wan Yusof, and Ahmad Mustafa Hashim. "Sensitivity Analysis of Hydroelectric Power Generation from Cascading Reservoirs." Advanced Materials Research 622-623 (December 2012): 1152–56. http://dx.doi.org/10.4028/www.scientific.net/amr.622-623.1152.

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The cascading reservoirs in Perak, Malaysia, were used to test the sensitivity analysis of hydroelectric power generation during refill and deplete period of the reservoirs. The cascading scheme comprises four reservoirs namely Temenggor, Bersia, Kenering and Chenderoh. The test was conducted after the analysis of water balance and stage-storage relationship of each reservoir in the cascading scheme. The result showed that power generation from the smaller reservoir, Bersia, is more sensitive to the change of headrace level, while the larger storage capacity and rated head reservoir is the most sensitive to the change of release. Therefore, to maximize the power generation from the cascading reservoir, the refill operations should be ranked according to the increasing order of the reservoir storage capacity and a reverse order should be followed during deplete period.
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6

McVay, D. A., and J. P. Spivey. "Optimizing Gas-Storage Reservoir Performance." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 173–78. http://dx.doi.org/10.2118/71867-pa.

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Summary As gas storage becomes increasingly important in managing the nation's gas supplies, there is a need to develop more gas-storage reservoirs and to manage them more efficiently. Using computer reservoir simulation to rigorously predict gas-storage reservoir performance, we present specific procedures for efficient optimization of gas-storage reservoir performance for two different problems. The first is maximizing working gas volume and peak rates for a particular configuration of reservoir, well, and surface facilities. We present a new, simple procedure to determine the maximum performance with a minimal number of simulation runs. The second problem is minimizing the cost to satisfy a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. We demonstrate a systematic procedure to determine the optimum combination of cushion gas volume, compression horsepower, and number and locations of wells. The use of these procedures is illustrated through application to gas-reservoir data. Introduction With the unbundling of the natural gas industry as a result of Federal Energy Regulatory Commission (FERC) Order 636, the role of gas storage in managing the nation's gas supplies has increased in importance. In screening reservoirs to determine potential gas-storage reservoir candidates, it is often desirable to determine the maximum storage capacity for specific reservoirs. In designing the conversion of producing fields to storage or the upgrading of existing storage fields, it is beneficial to determine the optimum combination of wells, cushion gas and compression facilities that minimizes investment. A survey of the petroleum literature found little discussion of simulation-based methodologies for achieving these two desired outcomes. Duane1 presented a graphical technique for optimizing gas-storage field design. This method allowed the engineer to minimize the total field-development cost for a desired peak-day rate and cyclic capacity (working gas capacity). To use the method, the engineer would prepare a series of field-design optimization graphs for different compressor intake pressures. Each graph consists of a series of curves corresponding to different peak-day rates. Each curve, in turn, shows the number of wells required to deliver the given peak-day rate as a function of the gas inventory level. Thus, the tradeoff between compression horsepower costs, well costs, and cushion gas costs could be examined to determine the optimum design in terms of minimizing the total field-development cost. Duane's method implicitly assumes that boundary-dominated flow will prevail throughout the reservoir. Henderson et al. 2 presented a case history of storage-field-design optimization with a single-phase, 2D numerical model of the reservoir. They varied well placement and well schedules in their study to reduce the number of wells necessary to meet the desired demand schedule. They used a trial-and-error method and stated that the results were preliminary. They found that wells in the poorest portion of the field should be used to meet demand at the beginning of the withdrawal period. Additional wells were added over time to meet the demand schedule. The wells in the best part of the field were held in reserve to meet the peak-day requirements, which occurred at the end of the withdrawal season. Coats3 presented a method for locating new wells in a heterogeneous field. His objective was to determine the optimum drilling program to maintain a contractual deliverability during field development. He provided a discussion of whether wells should be spaced closer together in areas of high kh or in areas of low kh. He found that when f h is essentially uniformly distributed, the wells should be closer together in low kh areas. On the other hand, if the variation in kh is largely caused by variations in h, or if porosity is highly correlated with permeability, wells should be closer together in areas of high kh. Coats' method assumes boundary-dominated flow throughout the reservoir. Wattenbarger4 used linear programming to solve the problem of determining the withdrawal schedule on a well-by-well basis that would maximize the total seasonal production, subject to constraints such as fixed demand schedule and minimum wellbore pressure. Van Horn and Wienecke5 solved the gas-storage-design optimization problem with a Fibonnaci Search algorithm. They expressed the investment requirement for a storage field in terms of four variables: cushion gas, number of wells, purification equipment, and compressor horsepower. They chose as the optimum design the combination of these four variables that minimized investment cost. The authors used an empirical backpressure equation, combined with a simplified gas material-balance equation, as the reservoir model. In this paper we present systematic, simulation-based methodologies for optimizing gas-storage reservoir performance for two different problems. The first is maximizing working gas volume and peak rates for a particular configuration of reservoir, well, and surface facilities. The second problem is minimizing the cost to satisfy a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. Constructing the Reservoir Model To optimize gas-storage reservoir performance, a model of the reservoir is required. We prefer to use the simplest model that is able to predict storage-reservoir performance as a function of the number and locations of wells, compression horsepower, and cushion gas volume. Although models combining material balance with analytical or empirical deliverability equations may be used in certain situations, a reservoir-simulation model is usually best, owing to its flexibility and its ability to handle well interference and complex reservoirs accurately. It is important to calibrate the model against historical production and pressure data; we must show that the model reproduces past reservoir performance accurately before we can use it to predict future performance with reliability. However, even calibrating the model by history matching past performance may not be adequate. It is our experience that information obtained during primary depletion of a reservoir is often not adequate to predict its performance under storage operations. Primary production over many years may mask layered or dual-porosity behavior that significantly affects the ability of the reservoir to deliver large volumes of gas within a 4- or 5-month period. Wells and Evans6 presented a case history of the Loop gas storage field, which exhibited this behavior. It may be necessary to implement a program of coring, logging, pressure-transient testing, and/or simulated storage production/injection testing to characterize the reservoir accurately.
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Solander, Kurt C., John T. Reager, Brian F. Thomas, Cédric H. David, and James S. Famiglietti. "Simulating Human Water Regulation: The Development of an Optimal Complexity, Climate-Adaptive Reservoir Management Model for an LSM." Journal of Hydrometeorology 17, no. 3 (February 12, 2016): 725–44. http://dx.doi.org/10.1175/jhm-d-15-0056.1.

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Abstract The widespread influence of reservoirs on global rivers makes representations of reservoir outflow and storage essential components of large-scale hydrology and climate simulations across the land surface and atmosphere. Yet, reservoirs have yet to be commonly integrated into earth system models. This deficiency influences model processes such as evaporation and runoff, which are critical for accurate simulations of the coupled climate system. This study describes the development of a generalized reservoir model capable of reproducing realistic reservoir behavior for future integration in a global land surface model (LSM). Equations of increasing complexity relating reservoir inflow, outflow, and storage were tested for 14 California reservoirs that span a range of spatial and climate regimes. Temperature was employed in model equations to modulate seasonal changes in reservoir management behavior and to allow for the evolution of management seasonality as future climate varies. Optimized parameter values for the best-performing model were generalized based on the ratio of winter inflow to storage capacity so a future LSM user can generate reservoirs in any grid location by specifying the given storage capacity. Model performance statistics show good agreement between observed and simulated reservoir storage and outflow for both calibration (mean normalized RMSE = 0.48; mean coefficient of determination = 0.53) and validation reservoirs (mean normalized RMSE = 0.15; mean coefficient of determination = 0.67). The low complexity of model equations that include climate-adaptive operation features combined with robust model performance show promise for simulations of reservoir impacts on hydrology and climate within an LSM.
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Nawaz, N. R., A. J. Adeloye, and M. Montaseri. "The Impact of Climate Change on Storage-Yield Curves for Multi-Reservoir Systems." Hydrology Research 30, no. 2 (April 1, 1999): 129–46. http://dx.doi.org/10.2166/nh.1999.0007.

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In this paper, we report on the results of an investigation into the impacts of climate change on the storage-yield relationships for two multiple-reservoir systems, one in England and the other in Iran. The impact study uses established protocol and obtains perturbed monthly inflow series using a simple runoff coefficient approach which accounts for non-evaporative losses in the catchment, and a number of recently published GCM-based scenarios. The multi-reservoir analysis is based on the sequent-peak algorithm which has been modified to analyse multiple reservoirs and to accommodate explicitly performance norms and reservoir surface fluxes, i.e. evaporation and rainfall. As a consequence, it was also possible to assess the effect of including reservoir surface fluxes on the storage-yield functions. The results showed that, under baseline conditions, consideration of net evaporation will require lower storages for the English system and higher storages for the Iranian system. However, with perturbed hydroclimatology different impacts were obtained depending on the systems' yield and reliability. Possible explanations are offered for the observed behaviours.
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Lee, Sang-Hyun, Sungtae Shin, Jin-Yong Choi, Jihoon Park, and Seung-Hwan Yoo. "Assessing the Resilience of Agricultural Reservoirs in Ungauged Catchments under Climate Change Using a Ratio Correction Factors-Based Calibration and Run Theory." Water 12, no. 6 (June 6, 2020): 1618. http://dx.doi.org/10.3390/w12061618.

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This study applied ratio correction factor (RCF) optimization to calibrate the daily storage of agricultural reservoirs located in ungauged catchments that lack stream flow data. Using Run theory, we then assessed the impacts of climate change on the resilience of agricultural reservoir operations during reservoir drought conditions. First, we optimized the RCFs of inflow and outflow in three agricultural reservoirs in Korea using limited measurement data from 2008 to 2017; the results showed high performance regarding the simulation of daily reservoir storage. Second, we simulated daily storage volume in reservoirs from 2018 to 2099, using future climate change data, and analyzed the duration and intensity of reservoir drought conditions, which indicated that the storage capacity is under the critical value. Without calibration, the correlation between the simulated and measured reservoir water volumes was very low, but the correlation increased after calibration of the simulated water volumes. A linear relationship between the simulated and measured volumes was observed with a correlation coefficient value of 0.9, indicating that the simulated reservoir values after calibration closely match the measured values. In addition, the maximum intensity of reservoir drought in the Kicheon reservoir was determined to be 486,000 m3 before calibration but 506,000 m3 after calibration. The duration results showed that long-term reservoir drought conditions will be observed more often in the future owing to climate change, and this could be a negative factor affecting the resilience of reservoir operations.
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Zhang, Shuai, and Huilin Gao. "Using the Digital Elevation Model (DEM) to Improve the Spatial Coverage of the MODIS Based Reservoir Monitoring Network in South Asia." Remote Sensing 12, no. 5 (February 25, 2020): 745. http://dx.doi.org/10.3390/rs12050745.

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Satellite remote sensing of near real-time reservoir storage variations has important implications for flood monitoring and water resources management. However, satellite altimetry data, which are essential for estimating storage variations, are only available for a limited number of reservoirs. This lack of high-density spatial coverage directly hinders the potential use of remotely sensed reservoir information for improving the skills of hydrological modeling over highly regulated river basins. To solve this problem, a reservoir storage dataset with high-density spatial coverage was developed by combining the water surface area estimated from Moderate Resolution Imaging Spectroradiometer (MODIS) imageries with the Digital Elevation Model (DEM) data collected by the Shuttle Radar Topography Mission (SRTM). By including more reservoirs, this reservoir dataset represents 46.6% of the overall storage capacity in South Asia. The results were validated over five reservoirs where gauge observations are accessible. The storage estimates agree well with observations, with coefficients of determination ranging from 0.47 to 0.91 and normalized root mean square errors (NRMSE) ranging from 15.46% to 37.69%. Given the general availability of MODIS and SRTM data, this algorithm can be potentially applied for monitoring global reservoirs at a high density.
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Dissertations / Theses on the topic "Storage reservoir"

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Srinivasan, Balaji S. "The impact of reservoir properties on mixing of inert cushion and natural gas in storage reservoirs." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4653.

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Thesis (M.S.)--West Virginia University, 2006.
Title from document title page. Document formatted into pages; contains vii, 88 p. : ill. (some col.), map (part col.). Includes abstract. Includes bibliographical references (p. 47-49).
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Ozturk, Bulent. "Simulation Of Depleted Gas Reservoir For Underground Gas Storage." Master's thesis, METU, 2004. http://etd.lib.metu.edu.tr/upload/12605723/index.pdf.

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For a natural gas importing country, &ldquo
take or pay&rdquo
approach creates problems since the demand for natural gas varies during the year and the excess amount of natural gas should be stored. In this study, an underground gas storage project is evaluated in a depleted gas Field M. After gathering all necessary reservoir, fluid, production and pressure data, the data were adapted to computer language, which was used in a commercial simulator software (IMEX) that is the CMG&rsquo
s (Computer Modelling Group) new generation adoptive simulator, to reach the history matching. The history matching which consists of the 4 year of production of the gas reservoir is the first step of this study. The simulation program was able to accomplish a good history match with the given parameters of the reservoir. Using the history match as a base, five different scenarios were created and forecast the injection and withdrawal performance of the reservoir. These scenarios includes 5 newly drilled horizontal wells which were used in combinations with the existing wells. With a predetermined injection rate of 13 MMcf/D was set for all the wells and among the 5 scenarios, 5 horizontal &ndash
6 vertical injectors &
5 horizontal - 6 vertical producers is the most successful in handling the gas inventory and the time it takes for a gas injection and production period. After the determination of the well configuration, the optimum injection rate for the entire field was obtained and found to be 130 MMcf/D by running different injection rates for all wells and then for only horizontal wells different injection rates were applied with a constant injection rate of 130 MMcf/d for vertical wells. Then it has been found that it is better to apply the 5th scenario which includes 5 horizontal &ndash
6 vertical injectors &
5 horizontal - 6 vertical producers having an injection rate of 130 MMcf/d for horizontal and vertical wells. Since within the 5th scenario, changing the injection rate to 1.3 Bcf/d and 13 Bcf/d, did not effect and change the average reservoir pressure significantly, it is best to carry out the project with the optimum injection rate which is 130 MMcf/d. The total gas produced untill 2012 is 394 BCF and the gas injected is 340 BCF where the maximum average reservoir pressure was recovered and set into a new value of 1881 psi by injection and cushion gas pressure as 1371 psi by withdrawal. If 5th scenario is compared with the others, there is an increase in injection and production performance about 90%.
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Rivera, Ramirez Hector David. "Flood control reservoir operations for conditions of limited storage capacity." Texas A&M University, 2004. http://hdl.handle.net/1969.1/1464.

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The main objective of this research is to devise a risk-based methodology for developing emergency operation schedules (EOS). EOS are decision tools that provide guidance to reservoir operators in charge of making real-time release decisions during major flood events. A computer program named REOS was created to perform the computations to develop risk-based EOS. The computational algorithm in REOS is divided in three major components: (1) synthetic streamflow generation, (2) mass balance computations, and (3) frequency analysis. The methodology computes the required releases to limit storage to the capacity available based on the probabilistic properties of future flows, conditional to current streamflow conditions. The final product is a series of alternative risk-based EOS in which releases, specified as a function of reservoir storage level, current and past inflows, and time of year, are associated with a certain risk of failing to attain the emergency operations objectives. The assumption is that once emergency operations are triggered by a flood event, the risk associated with a particular EOS reflects the probability of exceeding a pre-established critical storage level given that the same EOS is followed throughout the event. This provides reservoir operators with a mechanism for evaluating the tradeoffs and potential consequences of release decisions. The methodology was applied and tested using the Addicks and Barker Reservoir system in Houston, TX as a case study. Upstream flooding is also a major concern for these reservoirs. Modifications to the current emergency policies that would allow emergency releases based on the probability of upstream flooding are evaluated. Riskbased EOS were tested through a series of flood control simulations. The simulations were performed using the HEC-ResSim reservoir simulation model. Rainfall data recorded from Tropical Storm Allison was transposed over the Addicks and Barker watersheds to compute hypothetical hydrographs using HEC-HMS. Repeated runs of the HEC-ResSim model were made using different flooding and residual storage scenarios to compare regulation of the floods under alternative operating policies. An alternative application of the risk-based EOS in which their associated risk was used to help quantify the actual probability of upstream flooding in Addicks and Barker was also presented.
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Lekkala, Sudheer R. "Impact of injecting inert cushion gas into a gas storage reservoir." Morgantown, W. Va. : [West Virginia University Libraries], 2009. http://hdl.handle.net/10450/10335.

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Thesis (M.S.)--West Virginia University, 2009.
Title from document title page. Document formatted into pages; contains vii, 40 p. : col. ill. Includes abstract. Includes bibliographical references (p. 39-40).
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Sergienko, Ekaterina. "Adapted reservoir characterization for monitoring and uncertainty analysis of CO2 storage." Toulouse 3, 2012. http://thesesups.ups-tlse.fr/2019/.

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L'analyse de risques du stockage géologique de CO2 consiste à simuler la dynamique du processus de stockage et à évaluer la probabilité de fuites. L'approche proposée dans ce travail consiste à utiliser des surfaces de réponses basées sur les processus Gaussiens, cela permet de réduire le grand nombre d'appels au simulateur de réservoir nécessaire à cette analyse. Dans cette thèse des méthodes innovantes sont étudiées pour résoudre les problèmes suivants: 1. Emplacement des puits d'injection 2. Estimation de la fiabilité 3. Analyse de sensibilité fiabiliste Pour résoudre le premier problème nous proposons une méthode de surface de réponse pour gérer les paramètres discrets (positions des puits) et les sorties fonctionnelles discrètes (évolution de pression du réservoir). Par ailleurs, nous introduisons une nouvelle méthode pour la modélisation des réponses variées dans le temps. Pour cela, la caractérisation des courbes est effectuée en utilisant des modèles à forme invariante. Pour le problème de fiabilité, nous avons développé une approche combinant la méthode de réduction d'ensemble et le krigeage. Un échantillonnage adaptatif est construit afin d'améliorer itérativement l'estimation de la probabilité de défaillance du modèle. Pour répondre au dernier problème, nous proposons une méthode pour l'analyse de sensibilité fiabiliste. Elle est basée sur une perturbation de la distribution de probabilité des variables d'entrée afin de trouver les facteurs qui contribuent le plus à la variabilité de la probabilité de défaillance. Toutes les méthodes proposées ont été testées numériquement sur des exemples analytiques et des cas test de stockage de CO2
Risk analysis of CO2 geological storage involves the simulation of the dynamics of the storage process and the evaluation of the probability of the possible leakage events. The approach followed here focuses on Gaussian Process response surface modelling in order to reduce the number of calls to the expensive reservoir simulator. Three major problems related to uncertainty analysis of CO2 storage are addressed: 1. Injection well placement 2. Reliability estimation 3. Reliability sensitivity analysis To tackle the first problem we provide a response surface method to handle discrete parameters (well positions) and discrete functional outputs to treat responses varying trough time (reservoir pressure evolutions). In addition, we introduce a new method for modelling functional outputs based on curves characterization and involving shape invariant model. To address the reliability problem, we introduce a subset simulation algorithm linked with the Gaussian Process model. It involves adaptive experimental design refinement and the model updating. To solve the last problem we suggest a new method for reliability sensitivity analysis. It is based on a perturbation of a probability distribution of input variables in order to evaluate which one contributes the most in the variability of the failure probability. All the proposed methods have been numerically tested on analytical and CO2 storage examples
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6

Bhattacharya, Debashish. "Application of goal programming techniques for optimal reservoir operations." Thesis, Virginia Polytechnic Institute and State University, 1988. http://hdl.handle.net/10919/80096.

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The optimal reservoir operations problem consists of obtaining releases, storages of a reservoir and downstream reach routed flows such that benefits derived from operating the reservoir are maximized. These are obtained on the basis of forecasted inflows to the reservoir, and forecasted precipitation in the downstream reaches. Five goal programming schemes, namely (i) preemptive goal programming (ii) weighted goal programming (iii) minmax goal programming (iv) fuzzy goal programming and (v) interval goal programming are considered. The reservoir operation problem is also formulated as a multiobjective linear program (MOLP). It is shown that the optimal solutions of the goal programs are contained among the efficient points of the MOLP. It is also shown that the min max and fuzzy goal programs can yield inefficient points as optima; however, there exist alternate optima to these programs which are efficient. Therefore, it is suggested that one should solve an MOLP for considering alternative efficient solutions. These techniques are applied to the Green River basin system in Kentucky.
Master of Science
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Mullendore, Marina Anita Jacqueline. "Assessment of the Geological Storage Potential of Carbon Dioxide in the Mid-Atlantic Seaboard: Focus on the Outer Continental Shelf of North Carolina." Diss., Virginia Tech, 2019. http://hdl.handle.net/10919/100687.

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In an effort to mitigate carbon dioxide (CO2) emissions in the atmosphere, the Southeast Offshore Storage Resource Assessment (SOSRA) project has for objective to identify geological targets for CO2 storage in two main areas: the eastern part of the Gulf of Mexico and the Atlantic Ocean subsurface. SOSRA's second objective is to estimate the geological targets' capacity to store up to 30 million metric tons of CO2 each year with an error margin of ±30%. As part of this project, the research presented here focuses on the outer continental shelf of North Carolina and its potential for the deployment of large-scale offshore carbon storage in the near future. To identify geological targets, workflow followed typical early oil and gas exploration protocols: collecting existing datasets, selecting the most applicable datasets for reservoir exploration, and interpreting datasets to build a comprehensive regional geological framework of the subsurface of the outer continental shelf. The geomodel obtained can then be used to conduct static volumetric calculations estimating the storage capacity of each identified target. Numerous uncertainties regarding the geomodel were attributed to the variable coverage and quality of the geological and geophysical data. To address these uncertainties and quantify their potential impact on the storage capacity estimations, dynamic volumetric calculations (reservoir simulations) were conducted. Results have shown that, in this area, both Upper and Lower Cretaceous Formations have the potential to store large amounts of CO2 (in the gigatons range). However, sensitivity analysis highlighted the need to collect more data to refine the geomodel and thereby reduce the uncertainties related to the presence, dimensions and characteristics of potential reservoirs and seals. Reducing these uncertainties could lead to more accurate storage capacity estimations. Adequate injection strategies could then be developed based on robust knowledge of this area, thus increasing the probability of success for carbon capture and storage (CCS) offshore projects in North Carolina's outer continental shelf.
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Barton, Daniel Corey. "Determining CO2 Storage Potential: Characterization of Seal Integrity and Reservoir Failure in Exposed Analogs." DigitalCommons@USU, 2011. https://digitalcommons.usu.edu/etd/1118.

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Sequestration of carbon dioxide (CO2) into subsurface porous sandstone is proposed as a method for reducing accumulation of anthropogenic emissions of CO2 into the atmosphere. Natural exposures of reservoir and top-seal pairs in central and southeastern Utah are identified as analogs to proposed CO2 injection targets. Reservoir and top-seal pairs in natural analog exposures are analyzed in tandem to evaluate evidence for paleo-migration of fluids and/or hydrocarbons from the reservoir through the top seal. The San Rafael Swell and Monument Uplift exhibit similar structure and exposures of Jurassic units yet differ in amount and type of host rock alteration due to variable amounts and types of fluids and/or hydrocarbons that migrated along faults and fractures. Macroscopic scale analysis of each monocline included processing of satellite imagery, and creation of depth contour maps. At the mesoscopic scale, fracture spacing acquired from scanline station measurements identified increased fracture frequency in proximity to major fault zones. At the microscopic scale, percentage of degradation and type of mineralization in pore space were used to verify increased fluid flow in proximity to major fault zones. Faults with possible intersections with multiple antithetic faults at depth have an increased probability of allowing for upward migration of fluids and/or hydrocarbons along the fault plane and damage zone, effectively bypassing the top sealing formations. Fault leakage potential maps identified areas where seal bypass along major faults would likely occur during sequestration of CO2. The method was validated by identifying potential migration pathways for oil seeps on the Little Grand Wash fault in central Utah. The San Rafael Swell was geometrically modeled through restoration of eroded formation tops along the fold axis to quantify the interaction between an outward migrating CO2 plume and varying degrees of faulting and fracturing. Analysis of the migration of a CO2 plume front through time exhibits an increasing probability of the outward migrating plume intersecting a leaking feature, with the highest probability of the advancing plume intersecting a potentially leaking feature achieved when faults with 1+ km trace length and mean fracture spacing of 17 cm are taken into consideration. (177 pages)
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Nogueira, de Mago Marjorie Carolina. "Effect of flue gas impurities on the process of injection and storage of carbon dioxide in depleted gas reservoirs." Thesis, Texas A&M University, 2005. http://hdl.handle.net/1969.1/2613.

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Previous experiments - injecting pure CO2 into carbonate cores - showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this thesis, I report my findings on the effect of flue gas ??impurities?? on the displacement of natural gas during CO2 sequestration, and results on unconfined compressive strength (UCS) tests to carbonate samples. In displacement experiments, corefloods were conducted at 1,500 psig and 70??C, in which flue gas was injected into an Austin chalk core containing initially methane. Two types of flue gases were injected: dehydrated flue gas with 13.574 mole% CO2 (Gas A), and treated flue gas (N2, O2 and water removed) with 99.433 mole% CO2 (Gas B). The main results of this study are as follows. First, the dispersion coefficient increases with concentration of ??impurities??. Gas A exhibits the largest dispersion coefficients, 0.18-0.25 cm2/min, compared to 0.13-0.15 cm2/min for Gas B, and 0.15 cm2/min for pure CO2. Second, recovery of methane at breakthrough is relatively high, ranging from 86% OGIP for pure CO2, 74-90% OGIP for Gas B, and 79-81% for Gas A. Lastly, injection of Gas A would sequester the least amount of CO2 as it contains about 80 mole% nitrogen. From the view point of sequestration, Gas A would be least desirable while Gas B appears to be the most desirable as separation cost would probably be cheaper than that for pure CO2 with similar gas recovery. For UCS tests, corefloods were conducted at 1,700 psig and 65??C in such a way that the cell throughput of CO2 simulates near-wellbore throughput. This was achieved through increasing the injection rate and time of injection. Corefloods were followed by porosity measurement and UCS tests. Main results are presented as follows. First, the UCS of the rock was reduced by approximately 30% of its original value as a result of the dissolution process. Second, porosity profiles of rock samples increased up to 2.5% after corefloods. UCS test results indicate that CO2 injection will cause weakening of near-wellbore formation rock.
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Reisinger, Daniel L. "Water quantity and quality impacts of the proposed Everglades Agricultural Area Storage Reservoir--Phase 1." [Gainesville, Fla.] : University of Florida, 2006. http://purl.fcla.edu/fcla/etd/UFE0014421.

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Books on the topic "Storage reservoir"

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Unit, United States Soil Conservation Service Snow Survey and Water Supply Forecast. Reservoir operating guide, Ruby River Reservoir, Madison County, Montana. Bozeman, Mont: The Unit, 1986.

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Nakama, Lenore Y. Storage capacity of Fena Valley Reservoir, Guam, Mariana Islands, 1990. Honolulu, Hawaii: U.S. Dept. of the Interior, U.S. Geological Survey, 1992.

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Nakama, Lenore Y. Storage capacity of Fena Valley Reservoir, Guam, Mariana Islands, 1990. Honolulu, Hawaii: U.S. Dept. of the Interior, U.S. Geological Survey, 1992.

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Commission, Wyoming Water Development. Final report, Bridger Valley Reservoir project. Fort Collins, Colo: Short Elliott Hendrickson, 2008.

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Vaugh, Samuel K. Storage projection for reservoir systems: A case study of the Highland Lakes. Austin, Tex: Center for Research in Water Resources, Bureau of Engineering Research, Dept. of Civil Engineering, University of Texas at Austin, 1985.

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Nakama, Lenore Y. Storage capacity of Fena Valley Reservoir, Guam, Mariana Islands, 1990. Honolulu, Hawaii: U.S. Dept. of the Interior, U.S. Geological Survey, 1992.

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Stevens, Peter G. Willow Creek Basin hydrologic assessment of reservoir alternatives. Edmonton: Hydrology Branch, Technical Services Division, Water Resources Management Services, Alberta Environment, 1985.

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United States. Forest Service. Rocky Mountain Region. Rock Creek/Muddy Creek Reservoir: Final environmental impact statement : Muddy Creek, the preferred alternative. Lakewood, Colo: U.S. Forest Service, Rocky Mountain Region : $b Bureau of Land Management, Colorado State Office, 1990.

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Zsuffa, István. Reservoir sizing by transition probabilities: Theory, methodology, application. Littleton, Colo., USA: Water Resources Publications, 1987.

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Grah, Oliver J. Biological assessment for the Muddy Creek Reservoir project, Grand County. Craig, Colorado: U.S. Department of the Interior, Bureau of Land Management, Craig District Office, 1989.

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Book chapters on the topic "Storage reservoir"

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Ringrose, Philip, and Mark Bentley. "Models for Storage." In Reservoir Model Design, 251–76. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-70163-5_7.

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GOWANS, IAN, DANIEL MOYSEY, and PAUL WINFIELD. "Chapelton Flood Storage Reservoir." In Managing dams Challenges in a time of change, 376–87. London: Thomas Telford Ltd, 2010. http://dx.doi.org/10.1680/mdctc.40991.0032.

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Dor, Inka, Hanna Schechter, and Hether Bromley. "The Na’an Reservoir." In Hypertrophic Reservoirs for Wastewater Storage and Reuse, 305–26. Berlin, Heidelberg: Springer Berlin Heidelberg, 1999. http://dx.doi.org/10.1007/978-3-642-60112-5_20.

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Juanicó, Marcelo. "The Geta’ot Reservoir." In Hypertrophic Reservoirs for Wastewater Storage and Reuse, 327–53. Berlin, Heidelberg: Springer Berlin Heidelberg, 1999. http://dx.doi.org/10.1007/978-3-642-60112-5_21.

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Gafny, Sarig, and Avital Gasith. "The Enan Reservoir." In Hypertrophic Reservoirs for Wastewater Storage and Reuse, 369–87. Berlin, Heidelberg: Springer Berlin Heidelberg, 1999. http://dx.doi.org/10.1007/978-3-642-60112-5_24.

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LEE, S., J. CASS, S. CORNICK, and M. BRADLEY. "Cobbins Brook Flood Storage Reservoir." In Managing dams Challenges in a time of change, 364–75. London: Thomas Telford Ltd, 2010. http://dx.doi.org/10.1680/mdctc.40991.0031.

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Hülsmann, Stephan, Karsten Rinke, Lothar Paul, and Cristina Diez Santos. "Storage Reservoir Operation and Management." In Handbook of Water Resources Management: Discourses, Concepts and Examples, 777–99. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-60147-8_24.

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Eren, Jacob. "The Ma’aleh HaKishon Reservoir." In Hypertrophic Reservoirs for Wastewater Storage and Reuse, 355–60. Berlin, Heidelberg: Springer Berlin Heidelberg, 1999. http://dx.doi.org/10.1007/978-3-642-60112-5_22.

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Ma, Xinhua. "Banqiao Reservoir Geology and Storage Design." In Handbook of Underground Gas Storages and Technology in China, 1–19. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-7855-7_2-1.

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Ma, Xinhua. "Suqiao Reservoir Development and Storage Design." In Handbook of Underground Gas Storages and Technology in China, 1–19. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-7855-7_4-1.

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Conference papers on the topic "Storage reservoir"

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Chidambaram, Prasanna, Raj Deo Tewari, Siti Syareena Mohd Ali, and Chee Phuat Tan. "Understanding the Effect of Rock Compressibility on CO2 Storage Capacity Estimation in a Depleted Carbonate Gas Reservoir." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21207-ms.

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Abstract Avoiding or reducing greenhouse gases emission in the atmosphere requires extensive application of technologies and one of them is underground CO2 sequestration. Capture and storage of CO2 in depleted hydrocarbon reservoirs can reduce greenhouse gases released into the atmosphere effectively. Hydrocarbon reservoirs are considered one of the ideal geologic storage sites as they have held hydrocarbons over millions of years. Their architecture and properties are well understood due to exploration and production activities from these reservoirs. Storage projects require a large depleted hydrocarbon reservoir with good reservoir properties and are affected by several factors including voidage created by hydrocarbon production, pressure, architecture, formation permeability, aquifer influx, subsidence and compaction, and rock compressibility to name a few. Thus, realistic estimation of the storage capacity of the reservoir is a key step in the evaluation of CO2 storage plan. A good history matched simulation model incorporating the geomechanical parameters is essential to estimate storage capacity of the reservoir. Three major depleted gas reservoirs in Central Luconia field, located in offshore Sarawak, are being evaluated for future CO2 storage. Reservoir simulation is used as a tool to estimate future CO2 storage capacity of these reservoirs. Reliability of forecast from a reservoir simulation model is dependent on the quality of history match achieved. Hence it is believed that CO2 storage capacity estimates obtained from a good history matched simulation model must be reliable. However, during history matching exercise in these reservoirs, it was observed that an acceptable history match could be achieved with a range of rock compressibility values and aquifer influxes. Generally, a constant value of rock compressibility is used in conventional simulation. For example, in order to obtain an acceptable history match, with a lower compressibility, a larger aquifer influx is needed and vice versa. Interestingly, a forecast using these history match cases yield different CO2 storage capacities. A closer evaluation shows that aquifer influx has a strong impact on future CO2 storage capacity. An acceptable quality of history match can be obtained for a range of rock compressibility values when aquifer influx is adjusted along with it. Sensitivity analysis shows that future CO2 storage capacity in depleted hydrocarbon reservoir is sensitive to rock compressibility used in the simulation model. A detailed sensitivity analysis along with multiple history match scenarios is necessary to understand the range in future storage capacity when evaluating CO2 storage plan.
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Fawad, M., and N. H. Mondol. "Reservoir Characterisation Of Johansen Formation As Potential CO2 Storage Reservoir In The Northern North Sea." In Fifth CO2 Geological Storage Workshop. Netherlands: EAGE Publications BV, 2018. http://dx.doi.org/10.3997/2214-4609.201802962.

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McVay, D. A., and J. P. Spivey. "Optimizing Gas Storage Reservoir Performance." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1994. http://dx.doi.org/10.2118/28639-ms.

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Nghiem, Long, Vijay Shrivastava, David Tran, Bruce Kohse, Mohamed Hassam, and Chaodong Yang. "Simulation of CO2 Storage in Saline Aquifers." In SPE/EAGE Reservoir Characterization & Simulation Conference. European Association of Geoscientists & Engineers, 2009. http://dx.doi.org/10.3997/2214-4609-pdb.170.spe125848.

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Lazaro Vallejo, Lorena, Martin John Leahy, Tess Dance, and Tara C. LaForce. "New Phase Behavior Algorithm for Simulation of CO2 Storage." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 2011. http://dx.doi.org/10.2118/141734-ms.

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Stillwell, Ashlynn S., and Michael E. Webber. "Value of Reservoir Storage for Resilient Power Plant Cooling and Basin-Wide Water Availability." In ASME 2012 International Mechanical Engineering Congress and Exposition. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/imece2012-87150.

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Since many thermoelectric power plants use water for cooling, the power sector is vulnerable to droughts, heat waves, and other water constraints. At the same time, large water demands for power generation can strain water availability for other users in a river basin. Opportunities exist for power plants to decrease freshwater demands, increasing both drought resiliency of power plants and water availability for other users in the basin. One particular method of decreasing freshwater demands for power plants is by incorporating reservoir storage into cooling operations. Using reservoir storage allows water to be recirculated and reused for power plant cooling, thereby decreasing water withdrawal requirements. Water storage also has the added benefit of making water available during times of shortage. While storage is known to be beneficial, no tools exist to explicitly quantify the basin-wide water availability impacts and increased power generation resiliency possible via constructing water storage at thermoelectric power plants without existing reservoirs. Here we present the results of modeling efforts regarding the value (both in terms of resiliency and water availability) of reservoir storage for power plant cooling and basin-wide water availability in the Brazos and Colorado River basins, using a customized river basin based-model along with existing Texas Water Availability Models. Results vary between river basins and different water availability models, with construction of new reservoirs generally increasing basin-wide water availability in the Brazos River basin and generally decreasing basin-wide water availability in the Colorado River basin. We conclude that the value of reservoir storage for power plant resiliency and basin-wide water availability is highly site-specific.
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March, Rafael, Herwald Elder, Florian Doster, and Sebastian Geiger. "Accurate Dual-Porosity Modeling of CO2 Storage in Fractured Reservoirs." In SPE Reservoir Simulation Conference. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/182646-ms.

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Moncorgé, Arthur, Martin Petitfrère, and Sylvain Thibeau. "Complete EOS Thermal Formulation for Simulation of CO2 Storage." In SPE Offshore Europe Conference & Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205447-ms.

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Abstract Storage of CO2 in depleted gas reservoirs or large aquifers is one of the available solutions to reduce anthropogenic greenhouse gas emissions. Numerical modeling of these processes requires the use of large geological models with several orders of magnitude of variations in the porous media properties. Moreover, modeling the injection of highly concentrated and cold CO2 in large reservoirs with the correct physics is introducing numerical challenges that conventional reservoir simulators cannot handle. We propose a thermal formulation based on a full equation of state formalism to model pure CO2 and CO2 mixtures with the residual gas of depleted reservoirs. Most of the reservoir simulators model the phase-equilibriums with a pressure-temperature based formulation. With this usual framework, it is not possible to exhibit two phases with pure CO2 contents. Moreover, in this classical framework, the crossing of the phase envelope is associated with a large discontinuity in the enthalpy computation which can prevent the convergence of the energy conservation equation. In this work, accurate and continuous phase properties are obtained basing our formulation on enthalpy as a primary variable. We first implement a new phase-split algorithm with input variables as pressure and enthalpy instead of the usual pressure and temperature and we validate it on several test cases. This algorithm can model situations where the mixture can change rapidly from one phase to the other at constant pressure and temperature. Then treating enthalpy instead of temperature as a primary variable in both the reservoir and the well modeling algorithms, our reservoir simulator can model situations with pure or near pure components as well as crossing of the phase envelope that usual formulations implemented in reservoir simulators cannot handle. We first validate our new formulation against the usual formulation on a problem where both formulations can correctly represent the physics. Then we show situations where the usual formulations fail to represent the correct physics and that are simulated well with our new formulation. Finally, we apply our new model for the simulation of pure and cold CO2 injection in a real depleted gas reservoir from the Netherlands.
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Nghiem, Long X., Vijay Kumar Shrivastava, David Tran, Bruce Frederick Kohse, Mohamed Shamshudin Hassam, and Chaodong Yang. "Simulation of CO2 Storage in Saline Aquifers." In SPE/EAGE Reservoir Characterization and Simulation Conference. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/125848-ms.

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Al-Menhali, Ali, Catriona Reynolds, Peter Lai, Ben Niu, Norman Nicholls, John Peter Crawshaw, and Sam Krevor. "Advanced Reservoir Characterization for CO2 Storage." In International Petroleum Technology Conference. International Petroleum Technology Conference, 2014. http://dx.doi.org/10.2523/iptc-17253-ms.

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Reports on the topic "Storage reservoir"

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Ortiz, I., and R. Anthony. Underground natural gas storage reservoir management. Office of Scientific and Technical Information (OSTI), June 1995. http://dx.doi.org/10.2172/70175.

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Mclntire, Blayde, and Brian McPherson. Reservoir Engineering Optimization Strategies for Subsurface CO{sub 2} Storage. Office of Scientific and Technical Information (OSTI), September 2013. http://dx.doi.org/10.2172/1134753.

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Pruess, Karsten. On CO2 Behavior in the Subsurface, Following Leakage from aGeologic Storage Reservoir. Office of Scientific and Technical Information (OSTI), February 2006. http://dx.doi.org/10.2172/920245.

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Daley, T. M., M. A. Feighner, and E. L. Majer. Monitoring underground gas storage in a fractured reservoir using time lapse vsp. Office of Scientific and Technical Information (OSTI), March 2000. http://dx.doi.org/10.2172/764367.

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Liu, Guoxiang, Robert Dilmore, Shahab Mohaghegh, and Maher Alabboodi. Numerical Simulations of Geologic Storage Reservoir Management to Support Risk Mitigation Evaluation. Office of Scientific and Technical Information (OSTI), July 2021. http://dx.doi.org/10.2172/1807677.

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Okwen, Roland, Scott Frailey, Hannes Leetaru, and Sandy Moulton. Assessing Reservoir Depositional Environments to Develop and Quantify Improvements in CO2 Storage Efficiency. A Reservoir Simulation Approach. Office of Scientific and Technical Information (OSTI), September 2014. http://dx.doi.org/10.2172/1177419.

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Medeiros, Michael, Robert Booth, James Fairchild, Doug Imperato, Charles Stinson, Mark Ausburn, Mike Tietze, et al. Technical Feasibility of Compressed Air Energy Storage (CAES) Utilizing a Porous Rock Reservoir. Office of Scientific and Technical Information (OSTI), March 2018. http://dx.doi.org/10.2172/1434251.

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Medeiros, Michael. Technical Feasibility of Compressed Air Energy Storage (CAES) Utilizing a Porous Rock Reservoir (Appendix). Office of Scientific and Technical Information (OSTI), March 2018. http://dx.doi.org/10.2172/1432551.

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David G. Morse and Hannes E. Leetaru. RESERVOIR CHARACTERIZATION & 3D MODELS OF MT. SIMON GAS STORAGE FIELDS IN THE ILLINOIS BASIN. Office of Scientific and Technical Information (OSTI), September 2003. http://dx.doi.org/10.2172/825371.

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Medeiros, Michael. Technical Feasibility of Compressed Air Energy Storage (CAES) Utilizing a Porous Rock Reservoir, Appendix — Chapter 3. Office of Scientific and Technical Information (OSTI), March 2018. http://dx.doi.org/10.2172/1434263.

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