Download or read book Assessing the Effect of Reservoir Heterogeneity on CO2 Plume Migration Using Pressure Transient Analysis written by Aarti Dinesh Punase and published by . This book was released on 2012 with total page 282 pages. Available in PDF, EPUB and Kindle. Book excerpt: The ultimate success of carbon capture and storage project will be ensured only when there is a safe and effective permanent storage of CO2 for a significant amount of time without any leakages. Credible monitoring and verification is one of the most important aspects of CO2 sequestration. Accurate reservoir characterization is an important pre-requisite for the design, operation and economic success of processes like CO2 sequestration. The techniques available include geophysical and geochemical monitoring as well as numerical simulations using models replicating the field. In conducting the numerical simulations, it is required to assess the reservoir heterogeneity correctly. Previous work has shown that the injection data from wells can be utilized for developing models during CO2 sequestration to understand the spatial distribution of heterogeneities in the formation. In this research, we first understand and examine the information contained in the injection data for a wide range of reservoir models demonstrating different kinds of heterogeneities and rate fluctuations. We will confirm that the reservoir heterogeneities have an imprint on the injection pressure response and they influence CO2 plume migration significantly. Later we show that the effect of high or low permeability features along with rate fluctuations can provide considerable information about permeability heterogeneity in the reservoir. The applicability of this observation is made using field data from In-Salah gas field from central Algeria. Thus we demonstrate the feasibility of developing an inexpensive method of modeling reservoir heterogeneity by employing readily available measurements of injection pressure and rate to track CO2 migration. Later we describe method to find out what characteristics of the reservoir heterogeneities can be quantified using injection data (pressure and rate). The injection pressure response during CO2 sequestration will depend strongly on reservoir, fluid and well properties. A 3-D analytical model with infinite acting boundary is developed in CMG-GEM. Compositional reservoir simulation results from CMG-GEM simulator will be obtained and combined with pressure transient analysis and optimization algorithm for the prediction of reservoir parameters. In case of multiple injection wells in a heterogeneous formation, the analysis yield spatial variations in reservoir parameter groups like transmissibility (kh), permeability to porosity ratio ([kappa]/[phi]) in different part of the reservoir. These parameter groups can subsequently be used to constrain models of reservoir thickness, permeability and porosity. Thus, we imply that multiple reservoir attributes affect migration of CO2 plume and there is uncertainty associated with the estimation of these attributes. We present an approach to resolve some of that uncertainty using information extracted from injection well response.

Download or read book Plume Migration and Pressure Evolution Analyses for Recommendations in Offshore CO2 Storage Acreage Leasing Policy written by Melianna Ulfah and published by . This book was released on 2021 with total page 264 pages. Available in PDF, EPUB and Kindle. Book excerpt: This study inputs extensive geological and petrophysical data into a reservoir simulation to model the CO2 migration, analyze the plume and pressure distribution and evolution, and link the results to policy recommendations. I built a reservoir model, based on 3-D seismic interpretation of Middle Miocene strata, offshore Galveston, Texas and utilized well logs to characterize key intervals. The modeling investigated how far the CO2 plume would migrate under two scenarios: injecting CO2 at the base of the salt withdrawal basin (syncline scenario) and injecting CO2 at the base of the structural closure (base scenario). The simulation shows that by injecting the CO2 into the syncline, we need more acreage to be leased rather than injecting CO2 at the base of the structural closure for the same amount of CO2. The reason why syncline mechanism takes more acreage is because the geological layer around the injection point is more heterogeneous than the base scenario, thus making the CO2 tends to migrate laterally. On the positive side, such mechanism also limits the vertical migration of CO2, thus making syncline mechanism much less prone for the CO2 to escape to the upper geological layers. Moreover, the simulation also shows that with syncline scenario, the times needed for the reservoir to reach its stabilized pressure after the end of injections are faster. Another result of the simulation also shows that adding more wells into the study area would not significantly increase the storage capacity, and each well will suffer injectivity loss even more to maintain the reservoir pressure. Integrating the simulation results and existing policies for offshore CO2 storage, this study culminates several recommendations for the General Land Office regarding the acreage leasing policies. The main recommendation is to classify of the acreage valuation according to either the heterogeneity degree of the storage geology or the type of the structural closure targeted by the operator. Additionally, it is recommended for the GLO to closely evaluate and if necessary, limit the number of wells and operators for CO2 storage project operating in one elevated pressure area

Download or read book Local Capillary Trapping and Permeability retarded Accumulation During Geologic Carbon Sequestration written by Bo Ren and published by . This book was released on 2017 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Safe storage of CO2 in saline aquifers depends on CO2 migration rate, accumulation, and trapping inside saline aquifers that have intrinsic heterogeneity. This heterogeneity can be in both capillary entry pressure and permeability. The former heterogeneity causes local capillary trapping while the latter results in permeability-retarded accumulation. A main objective of this dissertation is to understand how both local capillary trapping and permeability-retarded accumulation secure CO2 storage. We establish a fast simulation technique to model local capillary trapping during CO2 injection into saline aquifers. In this technique, modeling efforts are decoupled into two parts: identifying trapping in a capillary entry pressure field and simulating CO2 flow in a permeability field. The former fields are correlated with the latter using the Leverett j-function. The first part describes an extended use of a geologic criterion originally proposed by Saadatpoor (2012). This criterion refers to a single value of 'critical capillary entry pressure' that is used to indicate barrier or local traps cells during buoyant flow. Three issues with the criterion are the unknown physical critical value, the massive overestimation of trapping, and boundary barriers. The first two issues are resolved through incorporating viscous flow of CO2. The last issue is resolved through creating periodic boundaries. This creation enables us to study both the amount and clusters of local capillary traps in infinite systems, and meanwhile the effects of reservoir heterogeneity, system size, aspect ratio, and boundary types are examined. In the second part, we adapt a connectivity analysis to assess CO2 plume dynamics. This analysis is then integrated into the geologic criterion to evaluate how injection strategies affect local capillary trapping in reservoirs. We demonstrate that reservoir heterogeneity affects the optimal injection strategies in terms of maximizing this trapping. We conduct analytical and numerical modeling of CO2 accumulations caused by both permeability hindrances and capillary barriers. The analytical model describes CO2 buoyant migration and accumulation at a low permeability region above a high-permeability region. In the limiting case of zero capillary pressure, the model equation is solved using the method of characteristics. The permeability-retarded accumulation is illustrated through CO2 saturation profiles and time-distance diagrams. Capillary trapping is subsequently accounted for by graphically incorporating the capillary pressure curve and capillary threshold effect. The relative importance of these two types of accumulations is examined under various buoyant source fluxes and porous media properties. Results demonstrate that accumulation estimate that account for only capillary trapping understates the amount of CO2 accumulated beneath low permeability structures during significant periods of a sequestration operation.

Download or read book Reservoir Compartmentalization written by S. J. Jolley and published by Geological Society of London. This book was released on 2010 with total page 376 pages. Available in PDF, EPUB and Kindle. Book excerpt: "Reservoir compartmentalization - the segregation of a petroleum accumulation into a number of individual fluid/pressure compartments - controls the volume of moveable oil or gas that might be connected to any given well drilled in a field, and consequently impacts 'booking' of reserves and operational profitability. This is a general feature of modern exploration and production portfolios, and has driven major developments in geoscience, engineering and related technology. Given that compartmentalization is a consequence of many factors, an integrated subsurface approach is required to better understand and predict compartmentalization behaviour, and to minimize the risk of it occurring unexpectedly. This volume reviews our current understanding and ability to model compartmentalization. It highlights the necessity for effective specialist discipline integration, and the value of learning from operational experience in: detection and monitoring of compartmentalization; stratigraphic and mixed-mode compartmentalization; and fault-dominated compartmentalization"--Page 4 of cover.

Download or read book Geologic Drivers Affecting Buoyant Plume Migration Patterns in Small scale Heterogeneous Media written by Priya Ravi Ganesh and published by . This book was released on 2012 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: CO2 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.

Download or read book Sensitivity Analysis of Carbon Dioxide Storage in Saline Aquifers in the Presence of a Gas Cap written by Silvia Veronica Solano and published by . This book was released on 2010 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Deep brine-bearing formations contain a significant CO2 storage potential as they are usually permeable sandstones at depths in which pressure and temperature conditions assure supercritical state for the injected CO2. When injecting CO2 in a hydrocarbon-rich area, presence of a gas cap significantly impacts the CO2 plume behavior. This study focuses on the assessment of the CO2 plume properties in formations typical of the Gulf Coast area, under the presence of a gas cap and its consequences for long-term storage. The study is prompted by the presence of a large depleted gas cap at Cranfield, Mississippi where CO2 is being injected for long-term storage. Presence of the gas cap, even depleted, near the injection site provides an exceptional opportunity to investigate an area made of higher compressibility fluids and its impact on reservoir and operational parameters, particularly CO2 plume behavior. Enhanced gas recovery is not planned within this area. Considerable volumes of native brine are displaced when large amounts of CO2 are injected, and when this displacement occurs in a closed system, the amount of stored CO2 will depend solely on the additional pore space available owing to compressibility of the pore structure and fluids. As a result, presence of a gas cap is expected to impact plume characteristics, as well as operational conditions, because of its larger compressibility. A multi-parameter sensitivity analysis, based on a generic reservoir model, was performed to appreciate relevant factors to CO2 migration under the influence of the nearby gas cap. It was achieved using the compositional reservoir simulator CMG-GEM and allied modules. Main parameters taken into account for the sensitivity analysis included variation in gas cap properties such as: volume, gas composition and gas residual saturation. Additionally, other parameters have been included in this study such as reservoir dip, injector-gas-cap distance, injection pressure, plume asymmetry and horizontal centroid location. The CO2 plume extends farther as the gas cap volume increases and the distance to the gas cap decreases. Gas residual saturation conditions in the gas cap region are not expected to affect the maximum lateral plume extent as much as the existent volume of gas. The effect of gas cap composition in CO2 migration is dominated by pressure changes within the formation which subsequently affects the gas cap compressibility and in consequence the plume maximum lateral extent. For example, contamination of a methane-rich gas cap by injected CO2 has a strong effect on the plume maximum lateral extent due to compressibility changes. This, in turn, affects regulatory Area of Review, project technical risks, and economics. In another part of the study, a dimensional analysis was performed to identify and assess dominant forces relevant to CO2 plume distribution in the presence of a gas cap. Dimensionless groups were used to express the relationship between centroid location and the ratio of gravity and viscous forces given by the gravity number. Appropriate assessment of gas cap impact on CO2 plume distribution and on aquifer pressure build-up is fundamental for developing an accurate economic outlook as well as for taking into account regulatory constraints (including a monitoring plan addressing leakage risk and possible aquifer contamination).

Download or read book Fundamental Analysis of Relative Permeability and Heterogeneity on Carbon Dioxide Storage and Plume Migration written by Nathan David Moodie and published by . This book was released on 2013 with total page 39 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Multilevel Pressure Measurements for Monitoring and Prediction of CO2 and Displaced Brine Migration written by Christin Weierholt Strandli and published by . This book was released on 2015 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: The motivation for the current work stems from the recent and unparalleled implementation of multilevel pressure monitoring at the Illinois Basin - Decatur Project (IBDP). The IBDP is a Carbon Capture and Sequestration (CCS) pilot project in Decatur, Illinois, USA, aimed to demonstrate the ability of the Cambrian-age Mt. Simon Sandstone to accept and store one million metric tons of CO2 over three years. The CO2 is captured from an ethanol plant owned by the Archer Daniels Midland Company (ADM), and injection into the lower portion of the Mt. Simon Sandstone started in November 2011. As part of an extensive Monitoring, Verification, and Accounting program, the Westbay multilevel groundwater characterization and monitoring system was installed in a deep in-zone verification (monitoring) well (2,000 m) to record the pressure at multiple depths before, during, and after CO2 injection. With two years of hourly pressure transient data available for analysis, the goal of this work was to establish whether (and to what extent) multilevel pressure transient data could provide valuable information on CO2 and displaced brine migration, both real-time and for forecasting. Based on a synthetic study and analyses of simulated pressure data, we show that pressure buildups normalized to the pressure buildup at the depth of injection and vertical pressure gradients normalized to the initial hydrostatic pressure gradient are diagnostic of reservoir structure (layering and anisotropy) soon after the start of injection and over time provide information on the height of the CO2 plume in the reservoir. The diagnostic features in the pressure response pertaining to the height of the CO2 plume are evident long before the CO2 arrives at the monitoring well and can be attributed to buoyancy induced and gravity segregated aqueous flows caused by the advancing CO2 plume. The multilevel pressure transient data acquired at the IBDP have provided a unique opportunity to validate the identified diagnostics for tracking buoyant migration of CO2 using multilevel pressure transient data. Based on diagnostics alone, the multilevel pressure transient data show that CO2 plume is confined largely to the injection interval, which is consistent with data from Reservoir Saturation Tool logs and sampling data. Hence, we successfully show that multilevel pressure transient data can be used to determine CO2 plume migration real-time. A thorough review of local and regional geology at the IBDP site points to a braided river system being the primary depositional environment in the lower portion of the Mt. Simon Sandstone where the CO2 is injected. Of particular interest is the presence and lateral extents of low-permeability layers that act as baffles and impede upward flow of CO2 and displaced brine. First, a layer-cake model (effectively 2D with laterally extensive layers and suitable for radial flow) is considered with focus on history matching. By history matching the multilevel pressure transient data at the IBDP at four different locations (injection well and three monitoring zones at the verification well), we show that it is possible to develop a highly resolved hydrogeologic model that in turn can be used to forecast future CO2 plume migration. Second, 3D models with focus on the uncertainty associated with non-extensive low-permeability layers are considered. Training images are generated to represent a simplified braided river system with sand interbedded with laterally non-extensive low-permeability layers. Conditioned to training images, well log data, and probability maps that capture various plausible configurations (model scenarios) of one specific layer of very low permeability (believed to stem from the deposition of a playa lake), multiple geologic model realizations are generated for each model scenario, and multiple permeability combinations are considered for each realization. At early time (as demonstrated in the synthetic diagnostics study), the multilevel pressure transients at the monitoring well are diagnostic of reservoir structure and insensitive to the type of fluid injected. Hence, early-time water injection (single-phase) simulations are used as proxy simulations in the place of full multiphase flow simulations, and pressure transient responses from the proxy simulations are compared to each other and to the IBDP "truth" using distance-based modeling. The calculated dissimilarities (distances between pressure transient responses) are clustered into groups that are diagnostic of average permeability properties and also provide information on which Playa Lake configurations to disregard based on early-time pressure transient data. Longer-time multiphase flow simulations are run on a few representative models to further constrain the uncertainty associated with low-permeability layers that may or may not restrict upward CO2 migration depending on their lateral extents. This work has shown that continuous multilevel pressure measurements at a monitoring well within the storage reservoir are useful for monitoring and predicting vertical CO2 plume migration. At early time, multilevel pressure transients are diagnostic of reservoir structure, which can aid in the prediction of future CO2 migration. At later times, information on the height of the buoyant CO2 plume within the storage reservoir is available.

Download or read book Understanding the Plume Dynamics and Risk Associated with CO2 Injection in Deep Saline Aquifers written by Abhishek Kumar Gupta and published by . This book was released on 2011 with total page 506 pages. Available in PDF, EPUB and Kindle. Book excerpt: Geological sequestration of CO2 in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The effectiveness of any CO2 sequestration operation depends on pore volume and the sequestration efficiency of the reservoir. Sequestration efficiency is defined here as the maximum storage with minimum risk of leakage to the overlying formations or to the surface. This can be characterized using three risk parameters i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO2 present at any time. The selection among prospective saline reservoirs can be expedited by developing some semi-analytical correlations for these risk parameters which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO2 sequestration. To develop such correlations, a database has been created from a large number of compositional reservoir simulations for different elementary reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip, perforation interval and constant pressure far boundary condition. This database is used to formulate different correlations that relate the sequestration efficiency to reservoir properties and operating conditions. The various elementary reservoir parameters are grouped together to generate different variants of gravity number used in the correlations. We update a previously reported correlation for time to hit the top seal and develop new correlations for other two parameters using the newly created database. A correlation for percentage of trapped CO2 is also developed using a previously created similar database. We find that normalizing all risk parameters with their respective characteristic values yields reasonable correlations with different variants of gravity number. All correlations confirm the physics behind plume movement in a reservoir. The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs. CO2 injection in saline reservoirs on the scale of tens of millions of tonnes may result in fracturing, fault activation and leakage of brine along conductive pathways. Critical contour of overpressure (CoP) is a convenient proxy to determine the risk associated with pressure buildup at different location and time in the reservoir. The location of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence and conductivity of faults). The CoP location also depends on relative permeability, and we extend the three-region injection model to derive analytical expressions for a specific CoP as a function of time. We consider two boundary conditions at the aquifer drainage radius, constant pressure or an infinite aquifer. The model provides a quick tool for estimating pressure profiles. Such tools are valuable for screening and ranking sequestration targets. Relative permeability curves measured on samples from seven potential storage formations are used to illustrate the effect on the CoPs. In the case of a constant pressure boundary and constant rate injection scenario, the CoP for small overpressures is time-invariant and independent of relative permeability. Depending on the relative values of overall mobilities of two-phase region and of brine region, the risk due to a critical CoP which lies in the two-phase region can either increase or decrease with time. In contrast, the risk due to a CoP in the drying region always decreases with time. The assumption of constant pressure boundaries is optimistic in the sense that CoPs extend the least distance from the injection well. We extend the analytical model to infinite-acting aquifers to get a more widely applicable estimate of risk. An analytical expression for pressure profile is developed by adapting water influx models from traditional reservoir engineering to the "three-region" saturation distribution. For infinite-acting boundary condition, the CoP trends depend on same factors as in the constant pressure case, and also depend upon the rate of change of aquifer boundary pressure with time. Commercial reservoir simulators are used to verify the analytical model for the constant pressure boundary condition. The CoP trends from the analytical solution and simulation results show a good match. To achieve safe and secure CO2 storage in underground reservoirs several state and national government agencies are working to develop regulatory frameworks to estimate various risks associated with CO2 injection in saline aquifers. Certification Framework (CF), developed by Oldenburg et al (2007) is a similar kind of regulatory approach to certify the safety and effectiveness of geologic carbon sequestration sites. CF is a simple risk assessment approach for evaluating CO2 and brine leakage risk associated only with subsurface processes and excludes compression, transportation, and injection-well leakage risk. Certification framework is applied to several reservoirs in different geologic settings. These include In Salah CO2 storage project Krechba, Algeria, Aquistore CO2 storage project Saskatchewan, Canada and WESTCARB CO2 storage project, Solano County, California. Compositional reservoir simulations in CMG-GEM are performed for CO2 injection in each storage reservoir to predict pressure build up risk and CO2 leakage risk. CO2 leakage risk is also estimated using the catalog of pre-computed reservoir simulation results. Post combustion CO2 capture is required to restrict the continuous increase of carbon content in the atmosphere. Coal fired electricity generating stations are the dominant players contributing to the continuous emissions of CO2 into the atmosphere. U.S. government has planned to install post combustion CO2 capture facility in many coal fired power plants including W.A. Parish electricity generating station in south Texas. Installing a CO2 capture facility in a coal fired power plant increases the capital cost of installation and operating cost to regenerate the turbine solvent (steam or natural gas) to maintain the stripper power requirement. If a coal-fired power plant with CO2 capture is situated over a viable source for geothermal heat, it may be desirable to use this heat source in the stripper. Geothermal brine can be used to replace steam or natural gas which in turn reduces the operating cost of the CO2 capture facility. High temperature brine can be produced from the underground geothermal brine reservoir and can be injected back to the reservoir after the heat from the hot brine is extracted. This will maintain the reservoir pressure and provide a long-term supply of hot brine to the stripper. Simulations were performed to supply CO2 capture facility equivalent to 60 MWe electric unit to capture 90% of the incoming CO2 in WA Parish electricity generating station. A reservoir simulation study in CMG-GEM is performed to evaluate the feasibility to recycle the required geothermal brine for 30 years time. This pilot study is scaled up to 15 times of the original capacity to generate 900 MWe stripping system to capture CO2 at surface.

Download or read book An Introduction to Reservoir Simulation Using MATLAB GNU Octave written by Knut-Andreas Lie and published by Cambridge University Press. This book was released on 2019-08-08 with total page 677 pages. Available in PDF, EPUB and Kindle. Book excerpt: Presents numerical methods for reservoir simulation, with efficient implementation and examples using widely-used online open-source code, for researchers, professionals and advanced students. This title is also available as Open Access on Cambridge Core.

Download or read book Investigation of Buoyant Plumes in a Quasi 2D Domain written by Yuhao Sun and published by . This book was released on 2014 with total page 336 pages. Available in PDF, EPUB and Kindle. Book excerpt: Leakage of stored bulk phase CO2 is one risk for sequestration in deep saline aquifers. As the less dense CO2 migrates upward within a storage formation or in layers above the formation, the security of its storage depends upon the trapping mechanisms that counteract the migration. The trapping mechanism motivating this research is local capillary trapping (LCT), which occurs during buoyancy-driven migration of bulk phase CO2 within a saline aquifer with spatially heterogeneous petrophysical properties. When a CO2 plume rising by buoyancy encounters a region where capillary entry pressure is locally larger than average, CO2 accumulates beneath the region. One benefit of LCT, applied specifically to CO2 sequestration and storage, is that saturation of stored CO2 phase is larger than the saturation for other permanent trapping mechanisms. Another potential benefit is security: CO2 that occupies local capillary traps remains there, even if the overlying formation that provides primary containment were to be compromised and allow leakage. Most work on LCT has involved numerical simulation (Saadatpoor 2010, Ganesh 2012); the research work presented here is a step toward understanding local capillary trapping at the bench scale. An apparatus and set of fluids are described which allow examining the extent of local capillary trapping, i.e. buoyant nonwetting phase immobilization beneath small-scale capillary barriers, which can be expected in typical heterogeneous storage formation. The bench scale environment analogous to CO2 and brine in a saline aquifer is created in a quasi-two dimensional experimental apparatus with dimension of 63 cm by 63 cm by 5 cm, which allows for observation of plume migration with physically representative properties but at experimentally convenient ambient conditions. A surrogate fluid pair is developed to mimic the density, viscosity and interfacial tension relationship found at pressure and temperature typical of storage aquifers. Porous media heterogeneity, pressure boundary conditions, migration modes of uprising nonwetting phase, and presence of fracture/breach in the capillary barrier are studied in series of experiments for their influences on LCT. A variety of heterogeneous porous media made of a range of sizes of loosely packed silica beads are used to validate and test the persistence of local capillary trapping mechanism. By adjusting the boundary conditions (fluid levels in reservoirs attached to top and to bottom ports of the apparatus), the capillary pressure gradient across the domain was manipulated. Experiments were conducted with and without the presence of fracture/potential leakage pathway in the capillary seal. The trapped buoyant phase remained secure beneath the local capillary barriers, as long as the effective capillary pressure exerted by the trapped phase (proportional to column height of the phase) is smaller than the capillary entry pressure of the barrier. The local capillary trapping mechanism remained persistent even under forced imbibition, in which a significantly higher hydraulic potential gradient, and therefore a larger gradient in capillary pressure, was applied to the system. The column height of buoyant fluid that remained beneath the local capillary barrier was smaller by a factor corresponding to the increase in capillary pressure gradient. Mimicking a breach of the caprock by opening valves at the top of the apparatus allowed buoyant mobile phase held beneath the valves to escape, but buoyant phase held in local traps at saturations above residual, and therefore potentially mobile, was undisturbed. This work provides systematic validation of a novel concept, namely the long-term security of CO2 that fills local (small-scale) capillary traps in heterogeneous storage formations. Results from this work reveal the first ever unequivocal experimental evidence on persistence of local capillary trapping mechanism. Attempts to quantify the nonwetting phase saturation and extent of LCT persistence serve as the initial steps to potentially reduce the risks associated with long-term storage security.

Download or read book Influence of Relative Permeability Curves on Extent of CO2 Plume During Injection Into Deep Saline Aquifers written by Sang-yeop Park and published by . This book was released on 2007 with total page 388 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Integrated Fault Seal Analysis written by S. Ogilvie and published by Geological Society of London. This book was released on 2020-08-03 with total page 290 pages. Available in PDF, EPUB and Kindle. Book excerpt: Faults commonly trap fluids such as hydrocarbons and water and therefore are of economic significance. During hydrocarbon field development, smaller faults can provide baffles and/or conduits to flow. There are relatively simple, well established workflows to carry out a fault seal analysis for siliciclastic rocks based primarily on clay content. There are, however, outstanding challenges related to other rock types, to calibrating fault seal models (with static and dynamic data) and to handling uncertainty. The variety of studies presented here demonstrate the types of data required and workflows followed in today’s environment in order to understand the uncertainties, risks and upsides associated with fault-related fluid flow. These studies span all parts of the hydrocarbon value chain from exploration to production but are also of relevance for other industries such as radioactive waste and CO2 containment.

Download or read book Geophysics and Geosequestration written by Thomas L. Davis and published by Cambridge University Press. This book was released on 2019-05-09 with total page 391 pages. Available in PDF, EPUB and Kindle. Book excerpt: An overview of the geophysical techniques and analysis methods for monitoring subsurface carbon dioxide storage for researchers and industry practitioners.

Download or read book FutureGen Project written by and published by . This book was released on 2007 with total page 138 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Reservoir Model Design written by Philip Ringrose and published by Springer. This book was released on 2014-10-03 with total page 260 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book gives practical advice and ready to use tips on the design and construction of subsurface reservoir models. The design elements cover rock architecture, petrophysical property modelling, multi-scale data integration, upscaling and uncertainty analysis. Philip Ringrose and Mark Bentley share their experience, gained from over a hundred reservoir modelling studies in 25 countries covering clastic, carbonate and fractured reservoir types. The intimate relationship between geology and fluid flow is explored throughout, showing how the impact of fluid type, production mechanism and the subtleties of single- and multi-phase flow combine to influence reservoir model design. Audience: The main audience for this book is the community of applied geoscientists and engineers involved in the development and use of subsurface fluid resources. The book is suitable for a range of Master’s level courses in reservoir characterisation, modelling and engineering. · Provides practical advice and guidelines for users of 3D reservoir modelling packages · Gives advice on reservoir model design for the growing world-wide activity in subsurface reservoir modelling · Covers rock modelling, property modelling, upscaling and uncertainty handling · Encompasses clastic, carbonate and fractured reservoirs

Download or read book Geological Carbon Storage written by Stéphanie Vialle and published by John Wiley & Sons. This book was released on 2018-11-15 with total page 372 pages. Available in PDF, EPUB and Kindle. Book excerpt: Geological Carbon Storage Subsurface Seals and Caprock Integrity Seals and caprocks are an essential component of subsurface hydrogeological systems, guiding the movement and entrapment of hydrocarbon and other fluids. Geological Carbon Storage: Subsurface Seals and Caprock Integrity offers a survey of the wealth of recent scientific work on caprock integrity with a focus on the geological controls of permanent and safe carbon dioxide storage, and the commercial deployment of geological carbon storage. Volume highlights include: Low-permeability rock characterization from the pore scale to the core scale Flow and transport properties of low-permeability rocks Fundamentals of fracture generation, self-healing, and permeability Coupled geochemical, transport and geomechanical processes in caprock Analysis of caprock behavior from natural analogues Geochemical and geophysical monitoring techniques of caprock failure and integrity Potential environmental impacts of carbon dioxide migration on groundwater resources Carbon dioxide leakage mitigation and remediation techniques Geological Carbon Storage: Subsurface Seals and Caprock Integrity is an invaluable resource for geoscientists from academic and research institutions with interests in energy and environment-related problems, as well as professionals in the field. Book Review: William R. Green, Patrick Taylor, Sven Treitel, and Moritz Fliedner, (2020), "Reviews," The Leading Edge 39: 214–216 Geological Carbon Storage: Subsurface Seals and Caprock Integrity, edited by Stéphanie Vialle, Jonathan Ajo-Franklin, and J. William Carey, ISBN 978-1-119-11864-0, 2018, American Geophysical Union and Wiley, 364 p., US$199.95 (print), US$159.99 (eBook). This volume is a part of the AGU/Wiley Geophysical Monograph Series. The editors assembled an international team of earth scientists who present a comprehensive approach to the major problem of placing unwanted and/or hazardous fluids beneath a cap rock seal to be impounded. The compact and informative preface depicts the nature of cap rocks and the problems that may occur over time or with a change in the formation of the cap rock. I have excerpted a quote from the preface that describes the scope of the volume in a concise and thorough matter. “Caprocks can be defined as a rock that prevents the flow of a given fluid at certain temperature, pressure, and chemical conditions. ... A fundamental understanding of these units and of their evolution over time in the context of subsurface carbon storage is still lacking.” This volume describes the scope of current research being conducted on a global scale, with 31 of the 83 authors working outside of the United States. The studies vary but can be generalized as monitoring techniques for cap rock integrity and the consequence of the loss of that integrity. The preface ends by calling out important problems that remain to be answered. These include imaging cap rocks in situ, detecting subsurface leaks before they reach the surface, and remotely examining the state of the cap rock to avert any problems. Chapter 3 describes how newer methods are used to classify shale. These advanced techniques reveal previously unknown microscopic properties that complicate classification. This is an example of the more we know, the more we don't know. A sedimentologic study of the formation of shale (by far the major sedimentary rock and an important rock type) is described in Chapter 4. The authors use diagrammatic examples to illustrate how cap rocks may fail through imperfect seal between the drill and wall rock, capillary action, or a structural defect (fault). Also, the shale pore structures vary in size, and this affects the reservoir. There are descriptions of the pore structure in the Eagle Ford and Marcellus shales and several others. Pore structures are analyzed using state-of-the-art ultra-small-angle X-ray or neutron scattering. They determine that the overall porosity decreases nonlinearly with time. There are examples of cap rock performance under an array of diagnostic laboratory analyses and geologic field examples (e.g., Marcellus Formation). The importance of the sequestration of CO2 and other contaminants highlights the significance of this volume. The previous and following chapters illuminate the life history of the lithologic reservoir seal. I would like to call out Chapter 14 in which the authors illustrate the various mechanisms by which a seal can fail and Chapter 15 in which the authors address the general problems of the effect of CO2 sequestration on the environment. They establish a field test, consisting of a trailer and large tank of fluids with numerous monitoring instruments to replicate the effect of a controlled release of CO2-saturated water into a shallow aquifer. This chapter's extensive list of references will be of interest to petroleum engineers, rock mechanics, and environmentalists. The authors of this volume present a broad view of the underground storage of CO2. Nuclear waste and hydrocarbons are also considered for underground storage. There are laboratory, field, and in situ studies covering nearly all aspects of this problem. I cannot remember a study in which so many different earth science resources were applied to a single problem. The span of subjects varies from traditional geochemical analysis with the standard and latest methods in infrared and X-ray techniques, chemical and petroleum engineering, sedimentary mineralogy, hydrology, and geomechanical studies. This volume is essential to anyone working in this field as it brings several disciplines together to produce a comprehensive study of carbon sequestration. While the volume is well illustrated, there is a lack of color figures. Each chapter should have at least two color figures, or there should be several pages of color figures bound in the center of the volume. Many of the figures would be more meaningful if they had been rendered in color. Also, the acronyms are defined in the individual chapters, but it would be helpful to have a list of acronyms after the extensive index. I recommend this monograph to all earth scientists but especially petroleum engineers, structural geologists, mineralogists, and environmental scientists. Since these chapters cover a broad range of studies, it would be best if the reader has a broad background. — Patrick Taylor Davidsonville, Maryland