Download or read book Development of a Rigorous Procedere to Predict CO2 Pressure and Temperature in an Injection Well Based on Analytical Models written by Arron A. Tchouka Singhe and published by . This book was released on 2012 with total page 202 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Prediction of Pressure and Temperature in CO2 Injection Wells Based on Analytical Modeling written by Arron A. Tchouka Singhe and published by Cuvillier Verlag. This book was released on 2013-05-03 with total page 240 pages. Available in PDF, EPUB and Kindle. Book excerpt: Injection into geological formations is seen by many as a short to medium term measure to reduce emissions of CO2 to the environment and as such to slowdown the pace of global warming. The injection process requires that the fluid flows effectively into the host formation. To this end it is very important to accurately predict the pressure and temperature of the fluid along the well and especially at the bottom of the hole. In the present dissertation a rigorous procedure to estimate fluid pressure and temperature along CO2 injection wells has been developed based on analytical modeling. The procedure accommodates wellbores of varying diameter, varying deviation angles, non-uniform tubing strings and layered formations with different thermal properties and varying geothermal gradients. To test the models, computer codes have been written with Visual Basic.Net language on the Microsoft Visual Studio Platform. The codes are encapsulated in a user-friendly Graphical User Interface. The simulated results are compared with field observed data from a shallow aquifer injection vertical well in Germany (Ketzin) and that from a relatively deeper offshore aquifer injection slanted well in Norway (Snøhvit). The maximum deviation is around 2% for pressure and around 10% for temperature.

Download or read book Investigation of Multiple Well Injections for Carbon Dioxide Sequestration in Aquifers written by Abhishek Joshi and published by . This book was released on 2014 with total page 38 pages. Available in PDF, EPUB and Kindle. Book excerpt: As the amount of CO2 present in the atmospheres is increasing due to combustion emission, it is becoming more and more important to find ways to reduce greenhouse gas emissions. One of the ways to do that is through carbon sequestration. Saline formations (aquifers) provide viable destination for carbon sequestration. The storage potential in these reservoirs is estimated at several thousands of Giga Tonnes (Gt) of CO2. Even though the capacity is substantial, the process of filling this capacity has a lot of challenges. Injection of large volumes within short period of time increases the formation pressure (which should be below fracture pressure) very fast. For each particular reservoir, injection capacity should be identified based on which CO2 can be injected within a particular injection area and time. In order to achieve this, an in-depth sensitivity study needs to be done on the various reservoir parameters such as thickness, rock compressibility, permeability, porosity, reservoir temperature and pressure, aquifer fracture pressure, number and placement of injection's wells. The objective of my Master's thesis work is finding ways to increase the storage injection capacity based on reservoir parameters and optimizing the well placement by identifying and developing analytical and numerical tools to do so. The research also focuses on conducting a sensitivity analysis on these parameters in order to find out the optimal injection scenario to obtain the amount of maximum CO2 sequestration in a reservoir. This study can help in the CO2 sequestration capacity predictions and screening suitable reservoir based on technical and economic criteria. In order to derive the injection capacity of the reservoir based on the reservoir parameters, two analytical models of multiple well injections were studied: i) Single-phase (Brine injection in a brine reservoir and ii) Two phase model (CO2 injection in a brine reservoir). In both cases, the aim is to analyse the pressure build-up and the results are discussed in terms of comparison with numerical simulations. Although analytical modeling is less accurate (compare to numerical) and restricted to vertical well injection it allows large number of realizations for sensitivity analysis to find significant patterns of the process and reduces the number of numerical simulations needed at final stages of optimization. Analysis is done by considering infinite acting, homogenous, isotropic and isothermal reservoir condition. The Ei-function approximation method was used to simulate results on pressure profile across the reservoir. Once we have a validated model, we look into increasing the CO2 injection capacity of saline aquifers by applying the multiple wells injection strategy. This was done by looking at the well interferences based on superposition principle and mapping the pressure build-up profile in the reservoir. Various approaches were used to get maximum injection capacity.

Download or read book Transient Flow Modelling of Carbon Dioxide CO2 Injection Into Depleted Gas Fields written by Revelation Jacob Samuel and published by . This book was released on 2019 with total page 249 pages. Available in PDF, EPUB and Kindle. Book excerpt: The internationally agreed global climate deal reached at the Paris Climate Conference in 2015 is intended to limit the increase in global average temperatures to "well below" 2°C above pre-industrial levels. This comes in addition to the European Union ambition for 80% to 95% reduction in the 1990 greenhouse gas emissions by 2050 in order to avoid dangerous climate change. Most scenario studies indicate that Carbon Capture and Storage (CCS) is essential for achieving such ambitious reductions. In CCS operations, depleted gas fields represent prime targets for large-scale storage of the captured CO2. Considering the relatively low wellhead pressure of such fields, the uncontrolled injection of the high-pressure dense phase CO2 will result in its rapid, quasi-adiabatic Joule-Thomson expansion leading to significant temperature drops. This could pose several risks, including blockage due to hydrate and ice formation following contact of the cold sub-zero CO2 with the interstitial water around the wellbore and the formation water in the perforations at the near well zone, thermal stress shocking and fracture of the wellbore casing steel and over-pressurisation accompanied by CO2 backflow into the injection system due to the violent evaporation of the superheated liquid CO2 upon entry into the wellbore. In order to minimise the above risks and develop best-practice guidelines for the injection of CO2, the accurate prediction of the CO2 pressure and temperature along the well during the injection process is of paramount importance. This thesis deals with the development and verification of a Homogeneous Equilibrium Mixture (HEM) model and a Homogenous Equilibrium Relaxation Mixture (HERM) model for simulating the transient flow phenomena taking place during the injection of dense phase CO2 into depleted gas fields. The HEM model assumes instantaneous interface mass, momentum and energy exchange between the constituent CO2 liquid and vapour phases. As such they remain at the same pressure, temperature and velocity, whence the corresponding fluid-flow may be described using a single set of mass, momentum and energy conservation equations. The HERM on the other hand presents an additional equation which accounts for the thermodynamic non-equilibrium thorough the introduction of a relaxation time. It also accounts for phase and flow dependent fluid/wall friction and heat transfer, variable well cross sectional area as well as deviation of the well from the vertical. At the well inlet, the opening of the upstream flow regulator valve is modelled as an isenthalpic expansion process; whilst at the well outlet, a formation-specific pressure-mass flow rate correlation is adopted to characterise the storage site injectivity. The testing of the models is based on their application to CO2 injection into the depleted 2582 m deep Goldeneye Gas Reservoir at Hewett field in the North Sea for which the required design and operational data are publically available. Varying injection scenarios involving the rapid (5 mins), medium (30 mins) and slow (2 hrs) linear ramping up of the injected CO2 flow rate to the peak nominal value of 33.5 kg/s are simulated. In each case, the simulated pressure and temperature transients at the top and bottom of the well are used to ascertain the risks of well-bore thermal shocking or interstitial ice formation leading to well blockage due to the rapid cooling of the CO2. Detailed sensitivity analysis of the most important parameters affecting the CO2 in-well flow behaviour, including the wellbore diameter variations, well inclination, upstream temperature, pressure and time variant injection mass flow rate are conducted. The simulation results obtained for a slow (2 hrs) flowrate ramp-up case using the HEM model produce a minimum wellhead temperature of - 11 oC. The corresponding minimum temperature using the HERM model on the other hand is - 21 oC, demonstrating the importance of accounting for non-equilibrium effects and the model"s usefulness as a tool for the development of optimal injection strategies for minimising the risks associated with the injection of CO2 into depleted gas fields.

Download or read book Geologic CO2 Storage written by YagnaDeepika Oruganti and published by . This book was released on 2010 with total page 612 pages. Available in PDF, EPUB and Kindle. Book excerpt: When CO2 is injected in deep saline aquifers on the scale of gigatonnes, pressure buildup in the aquifer during injection will be a critical issue. Because fracturing, fault activation and leakage of brine along pathways such as abandoned wells all require a threshold pressure (Nicot et al., 2009); operators and regulators will be concerned with the spatial extent of the pressure buildup. Thus a critical contour of overpressure is a convenient proxy for risk. The location of this contour varies depending on the target aquifer properties (porosity, permeability etc.), the geology (presence of faults, abandoned wells etc.), and boundary conditions. Importantly, the extent also depends on relative permeability (Burton et al., 2008). First we describe ways of quantifying the risk due to pressure buildup in an aquifer with a constant pressure boundary, using the three-region injection model to derive analytical expressions for a specific contour of overpressure at any given time. All else being the same, the two-phase-region mobilities (and hence relative permeability characteristics) provide a basis for the ranking of storage formations based on risk associated with pressure elevation during injection. The pressure buildup during CO2 injection will depend strongly upon the boundary conditions at the boundary of the storage formation. An analytical model for pressure profile in the infinite-acting aquifer is developed by combining existing water influx models in traditional reservoir engineering (Van-Everdingen and Hurst model, Carter-Tracy model) to the current problem for describing brine efflux from the storage aquifer when CO2 injection creates a "three-region" saturation distribution. We determine evolution of overpressure with time for constant pressure, no-flow and infinite-acting boundary conditions, and conclude that constant pressure and no-flow boundary conditions give the most optimistic and pessimistic estimates of risk respectively. Compositional reservoir simulation results, using CMG-GEM simulator are presented, to show the effect of an isolated no-flow boundary on pressure buildup and injectivity in saline aquifers. We investigate the effect of multiple injection wells on single-phase fluid flow on aquifer pressure buildup, and demonstrate the use of an equivalent injection well concept to approximate the aquifer pressure profile. We show a relatively inexpensive method of predicting the presence of unanticipated heterogeneities in the formation, by employing routine measurements such as injection rate and injection pressure to track deviation in the plume path. This idea is implemented by combining Pro-HMS (probabilistic history matching software, that carries out geologically consistent parameter estimation), and a CMG-GEM model which has been tuned to the physics of the CO2-brine system.

Download or read book Modeling Injection Induced Fractures and Their Impact in CO2 Geological Storage written by Zhiyuan Luo and published by . This book was released on 2013 with total page 358 pages. Available in PDF, EPUB and Kindle. Book excerpt: Large-scale geologic CO2 storage is a technically feasible way to reduce anthropogenic emission of green house gas to atmosphere by human beings. In large-scale geologic CO2 sequestration, high injection rate is required to satisfy economics and operational considerations. During the injection phase, temperature and pressure of the storage aquifers may vary significantly with the introduced CO2. These changes would re-distribute the in-situ stresses in formations and induce fracture initiation or even propagation. If fractures are not permitted by regulators, then the injection operation strategies must be supervised and designed to prevent fracture initiation, and the storage formations should be screened for risk of fracturing. In more flexible regulatory environment, if fractures are allowed, fractures would strongly influence the CO2 migration profile and storage site usage efficiency depending on fracture length and growth rate. In this dissertation, we built analytical heat transfer models for vertical and horizontal injection wells. The models account for the dependency of overall heat transfer coefficient on injection rate to more accurately predict the borehole temperature. Based on these models, we can calculate temperature change in formation surrounding wellbores and thus evaluate thermo-elastic stress around borehole as well as its impact on fracture initiation pressure. By considering the impact of thermo-elastic effect on fracturing pressure, we predicted maximum injection rate avoiding fracture initiation and provided injection and storage strategies to increase the maximum safe injection rate. The results show that thermo-elastic stress significantly limits maximum injection rate for no-fractured injection scenario, especially for horizontal injectors. To improve injection rate, partial perforation and pre-heating CO2 before injection have been designed, and results shows that these strategies can strongly negate thermo-elastic influence for various injection scenarios. On the other hand, the model provides parametric analysis on geological and operational conditions of CO2 storage project for site screening work. In the case of permitting fracture occurrence, a semi-analytical model was built to quantitatively describe fracture propagation and injected fluid migration profile of a fractured vertical injector for storage systems with various boundary conditions. We examined the correlation between fracture growth and CO2 migration in various injection scenarios. Two-phase fractional flow model of Buckley-Leverett theory has been extended to account for the CO2-brine three-region flow system (dry CO2, CO2-brine, and brine) from a fractured injector. In the sensitivity study, fracture growth and fluid migration greatly depend on Young's modulus of the formation rock and storage site boundary conditions. Consequently, the results show that fast growing, long fractures may yield a flooding pattern with large aspect ratio, as well as early breakthrough at the drainage boundary; in contrast, slow growing short fractures provides high injectivity without changing flooded area shape. We studied the physics for issues related to injection induced fractures in geologic CO2 sequestration in saline aquifers, assessed risk associated to them and developed low cost and quick analytical models. These models could easily provide predictions on maximum injection rate in no-fracture regulation CO2 storage projects as well as estimate fracture growth and injected fluid migration under fracture allowable scenarios. "Preferred storage aquifers" have following properties: larger permeability, deep formation, no over pressure, low Young's modulus and low Poisson's ratio and open boundaries. In many practical cases, however, injection strategies have to be designed if some properties of formation are out of ideal range. Besides applications in CO2 storage, the approach and model we developed can also be applied into any injection induced fracture topics, namely water/CO2 flooding and wasted water re-injection.

Download or read book An Efficient Deep Learning Based Workflow for CO2 Plume Imaging Considering Model Uncertainties Using Distributed Pressure and Temperature Measurements written by Masahiro Nagao and published by . This book was released on 2022 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Effective monitoring of CO2 plume is critical to environmental safety throughout the life-cycle of a geologic CO2 sequestration project. Although full physics-based techniques such as history matching with numerical simulations can be used for predicting the evolution of underground CO2 saturation, the computational cost of the high-fidelity simulations can be prohibitive. Recent development in data-driven models can provide a viable alternative for rapid prediction of the CO2 plume based on readily available pressure and temperature measurements. In this study, we present a novel deep learning-based workflow that can efficiently visualize CO2 plume in near real-time with considering the uncertainties of CO2 plume images. 'Deep learning' refers to a data-driven input-output model development approach involving artificial neural networks with many hidden layers. Our deep learning workflow utilizes field measurements, such as downhole pressure, temperature, and flowrates as input to visualize the subsurface CO2 plume images as a propagating CO2 saturation front in terms of 'onset time'. The 'onset time' is the calendar time when the CO2 saturation at a given location exceeds a specified threshold value. Rather than storing CO2 saturation at multiple time steps, the onset time compresses the data into a single image of CO2 front propagation. To start with, we generate a comprehensive training dataset using flow simulation with diverse geologic model realizations and fluid models. The training data consists of injection rate/pressure at the injection well and measurements in monitoring wells (e.g., distributed pressure and temperature data) and the corresponding CO2 plume propagation onset time maps. To build a machine learning model for CO2 plume evolution, the simple and straight-forward way would be to train a deep learning-based regression model where the input consists of the field measurements, and the output is CO2 saturation distribution at different times. However, the high output dimension of spatial resolution and temporal steps make the training inefficient and impractical. We address this challenge in two ways: first, we output a single onset time map rather than multiple saturation maps at different times; second, we apply a variational autoencoder-decoder (VAE) network that uses lower dimensional latent variables for compressing high dimensional output images, namely the CO2 onset time maps are used as input and output of the VAE network. The use of onset time and image compression using VAE considerably simplifies the deep learning architecture and also makes the training more efficient. In our approach, a feed forward neural network model is trained to predict latent variables of the VAE network. Subsequently the latent variables are fed to the trained decoder network to generate the 3D onset time image, visualizing the evolving CO2 plume in near real time. Since the VAE is used for dimensionality reduction, the trained neural network can provide multiple CO2 plume image predictions considering the uncertainties.The power and efficacy of our approach are demonstrated using both synthetic and field applications. We first demonstrate the deep learning-based CO2 plume imaging workflow using a synthetic example. Next, the visualization workflow is applied to a CO2-enhanced oil recovery and associated geological storage project in a carbonate reef reservoir in the Northern Niagaran Pinnacle Reef Trend in Michigan, USA. The monitoring data set consists of distributed temperature sensing (DTS) data and time-lapse pressure measurements at several locations along the monitoring well. The CO2 plume images obtained from the proposed data-driven approach are compared with the approach based on flow simulation and history matching of 3D geologic models, where similar results are obtained. Additionally, an efficient workflow for optimizing data acquisition and measurement type is demonstrated using our deep learning-based framework.The novelty of this work is the development and application of a deep learning-based framework to interpret field measurements as CO2 plume images. The flexibility of the data-driven workflow allows us to incorporate diverse data types, and the efficiency of the method makes the approach suitable for field-scale applications.

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 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 Petrophysical Modeling and Simulation Study of Geological CO2 Sequestration written by Xianhui Kong and published by . This book was released on 2014 with total page 452 pages. Available in PDF, EPUB and Kindle. Book excerpt: Global warming and greenhouse gas (GHG) emissions have recently become the significant focus of engineering research. The geological sequestration of greenhouse gases such as carbon dioxide (CO2) is one approach that has been proposed to reduce the greenhouse gas emissions and slow down global warming. Geological sequestration involves the injection of produced CO2 into subsurface formations and trapping the gas through many geological mechanisms, such as structural trapping, capillary trapping, dissolution, and mineralization. While some progress in our understanding of fluid flow in porous media has been made, many petrophysical phenomena, such as multi-phase flow, capillarity, geochemical reactions, geomechanical effect, etc., that occur during geological CO2 sequestration remain inadequately studied and pose a challenge for continued study. It is critical to continue to research on these important issues. Numerical simulators are essential tools to develop a better understanding of the geologic characteristics of brine reservoirs and to build support for future CO2 storage projects. Modeling CO2 injection requires the implementation of multiphase flow model and an Equation of State (EOS) module to compute the dissolution of CO2 in brine and vice versa. In this study, we used the Integrated Parallel Accurate Reservoir Simulator (IPARS) developed at the Center for Subsurface Modeling at The University of Texas at Austin to model the injection process and storage of CO2 in saline aquifers. We developed and implemented new petrophysical models in IPARS, and applied these models to study the process of CO2 sequestration. The research presented in this dissertation is divided into three parts. The first part of the dissertation discusses petrophysical and computational models for the mechanical, geological, petrophysical phenomena occurring during CO2 injection and sequestration. The effectiveness of CO2 storage in saline aquifers is governed by the interplay of capillary, viscous, and buoyancy forces. Recent experimental data reveals the impact of pressure, temperature, and salinity on interfacial tension (IFT) between CO2 and brine. The dependence of CO2-brine relative permeability and capillary pressure on IFT is also clearly evident in published experimental results. Improved understanding of the mechanisms that control the migration and trapping of CO2 in the subsurface is crucial to design future storage projects for long-term, safe containment. We have developed numerical models for CO2 trapping and migration in aquifers, including a compositional flow model, a relative permeability model, a capillary model, an interfacial tension model, and others. The heterogeneities in porosity and permeability are also coupled to the petrophysical models. We have developed and implemented a general relative permeability model that combines the effects of pressure gradient, buoyancy, and capillary pressure in a compositional and parallel simulator. The significance of IFT variations on CO2 migration and trapping is assessed. The variation of residual saturation is modeled based on interfacial tension and trapping number, and a hysteretic trapping model is also presented. The second part of this dissertation is a model validation and sensitivity study using coreflood simulation data derived from laboratory study. The motivation of this study is to gain confidence in the results of the numerical simulator by validating the models and the numerical accuracies using laboratory and field pilot scale results. Published steady state, core-scale CO2/brine displacement results were selected as a reference basis for our numerical study. High-resolution compositional simulations of brine displacement with supercritical CO2 are presented using IPARS. A three-dimensional (3D) numerical model of the Berea sandstone core was constructed using heterogeneous permeability and porosity distributions based on geostatistical data. The measured capillary pressure curve was scaled using the Leverett J-function to include local heterogeneity in the sub-core scale. Simulation results indicate that accurate representation of capillary pressure at sub-core scales is critical. Water drying and the shift in relative permeability had a significant impact on the final CO2 distribution along the core. This study provided insights into the role of heterogeneity in the final CO2 distribution, where a slight variation in porosity gives rise to a large variation in the CO2 saturation distribution. The third part of this study is a simulation study using IPARS for Cranfield pilot CO2 sequestration field test, conducted by the Bureau of Economic Geology (BEG) at The University of Texas at Austin. In this CO2 sequestration project, a total of approximately 2.5 million tons supercritical CO2 was injected into a deep saline aquifer about ~10000 ft deep over 2 years, beginning December 1st 2009. In this chapter, we use the simulation capabilities of IPARS to numerically model the CO2 injection process in Cranfield. We conducted a corresponding history-matching study and got good agreement with field observation. Extensive sensitivity studies were also conducted for CO2 trapping, fluid phase behavior, relative permeability, wettability, gravity and buoyancy, and capillary effects on sequestration. Simulation results are consistent with the observed CO2 breakthrough time at the first observation well. Numerical results are also consistent with bottomhole injection flowing pressure for the first 350 days before the rate increase. The abnormal pressure response with rate increase on day 350 indicates possible geomechanical issues, which can be represented in simulation using an induced fracture near the injection well. The recorded injection well bottomhole pressure data were successfully matched after modeling the fracture in the simulation model. Results also illustrate the importance of using accurate trapping models to predict CO2 immobilization behavior. The impact of CO2/brine relative permeability curves and trapping model on bottom-hole injection pressure is also demonstrated.

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 0 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 Implementation of the Helgeson Kirkham Flowers Model to Study Reservoir Temperature Evolution During CO2 Injection written by Christopher Charles Binter and published by . This book was released on 2012 with total page 57 pages. Available in PDF, EPUB and Kindle. Book excerpt: A comprehensive one-dimensional numerical heat transfer module has been implemented into an existing reactive transport modeling application to study the temperature effects resulting from CO2-rich injection into sedimentary basins. The temperature module iteratively calculates thermophysical properties of charged aqueous solutes and uses these properties to compute a spatial and temporal temperature profile. An advection-diffusion model governing heat transport is solved using a finite volume method with solute specific partial molal enthalpy and partial molal heat capacity values obtained using the Helgeson-Kirkham-Flowers (HKF) model. The temperature module has been used to study the temperature effects resulting from injection of CO2-rich water into the Oligocene Frio Formation along the Texas Gulf Coast, with simulation parameters similar to the Frio Test Pilot Experiment. Simulation results were compared to bottom hole temperature data obtained from an observation well 30 meters away from the injection well during the injection phase. Results show an increase in temperature caused by the arrival of the CO2- rich injectant that is in agreement with the well data. Results further show small variations in injection rate and pressure have little effect on the temperature increase; while changing total carbon concentration in the injectant water has a direct impact on temperature. The simulated temperature profile correlates with other simulation results that show an increase in temperature resulting from CO2 injection. Temperature signatures predicted by numerical simulation could be used to monitor the migration of CO2-rich plumes. This module can also be used to conduct what-if scenarios to determine the maximum amount of CO2 that can be sequestered in a formation without exceeding a critical reservoir temperature that could damage instruments and seals.

Download or read book Modeling CO2 Leakage from Geological Storage Formation and Reducing the Associated Risk written by Qing Tao (Ph. D.) and published by . This book was released on 2012 with total page 384 pages. Available in PDF, EPUB and Kindle. Book excerpt: Large-scale geological storage of CO2 is likely to bring CO2 plumes into contact with existing wellbores and faults, which can act as pathways for leakage of stored CO2 Modeling the flux of CO2 along a leaky pathway requires transport properties along the pathway. We provide an approach based on the analogy between the leakage pathway in wells that exhibit sustained casing pressure (SCP) and the rate-limiting part of the leakage pathway in any wellbore that CO2 might encounter. By using field observations of SCP to estimate transport properties of a CO2 leakage pathway, we obtain a range of CO2 fluxes for the cases of buoyancy-driven (post-injection) and pressure-driven (during injection) leakage. The fluxes in example wells range from background levels to three orders of magnitude higher than flux at the natural CO2 seep in Crystal Geyser, Utah. We estimate a plausible range of fault properties from field data in the Mahogany Field using a shale gouge ratio correlation. The estimated worst-case CO2 flux is slightly above background range. The flux along fault could be attenuated to zero by permeable layers that intersect the fault. The attenuation is temporary if layers are sealed at other end. Counterintuitively, greater elevation in pressure at the base of the fault can result in less CO2 leakage at the top of the fault, because the capillary entry pressure is exceeded for more permeable layers. Since non-negligible leakage rates are possible along wellbores, it is important to be able to diagnose whether leakage is occurring. Concurrent pressure and temperature measurements are especially valuable because they independently constrain the effective permeability of a leakage path along wellbore. We describe a simple set of coupled analytical models that enable diagnosis of above-zone monitoring data. Application to data from a monitoring well during two years of steady CO2 injection shows that the observed pressure elevation requires a model with an extremely large leakage rate, while the temperature model shows that this rate would be large enough to raise the temperature in the monitoring zone significantly, which is not observed. The observation well is unlikely to be leaking. Extraction of brine from the aquifer offers advantage over standard storage procedure by greatly mitigating pressure elevation during CO2 injection. A proper management of the injection process helps reduce the risk of leakage associated with wellbores and faults. We provide strategies that optimize the injection of CO2 which involve extraction of brine in two scenarios, namely injecting dissolved CO2 and supercritical CO2. For surface dissolution case we are concerned with bubble point contour, while for supercritical CO2 injection we are concerned with breakthrough of CO2 at extractors. In a surface dissolution project, the CO2 concentration front shape when it reaches the saturation pressure contour defines the maximum areal extent of CO2-saturated brine and hence the aquifer utilization efficiency. We illustrate the reduction of utilization efficiency due to heterogeneity of the aquifer. We develop an optimal control strategy of the injection/extraction rates to maximize the utilization efficiency. We further propose an optimal well pattern orientation strategy. Results show that the approach nearly compensates the reduction of utilization efficiency due to heterogeneity. In a supercritical CO2 injection that involves brine extraction, the problem of avoiding breakthrough of CO2 at extraction wells can be addressed by optimizing flow rates at each extractor and injector to delay breakthrough as long as possible. We use the Capacitance-Resistive Model (CRM) to conduct the optimization. CRM runs rapidly and requires no prior geologic model. Fitting the model to data recorded during early stages of CO2 injection characterizes the connectivities between injection and brine-extraction wells. The fitted model parameters are used to optimize subsequent CO2 injection in the formation. Field illustration shows a significant improvement in CO2 storage efficiency.

Download or read book Optimization of Multiple Wells in Carbon Sequestration written by Swathi Gangadharan and published by . This book was released on 2014 with total page 69 pages. Available in PDF, EPUB and Kindle. Book excerpt: Injection of CO2 in saline aquifers is considered as one of the best strategies for the reduction of greenhouse gases. In order to select a potential saline aquifer storage site for carbon sequestration, many parameters are considered such as relative permeability, thickness, compressibility, porosity, salinity and well interference. These are significant because they affect the CO2 storage capacity of the reservoir. The one of the most important criteria to be considered during sequestration is the pressure profile inside the reservoir as the sequestered CO2 increases the pressure within the saline formation over time. In order to maintain the integrity of the reservoir, the reservoir pressure is always maintained below the fracture pressure. Thus, modeling of pressure profile is essential as it controls the maximum amount of CO2 which can be into the reservoir. There are various analytical and numerical models to determine the bottom-hole pressure for CO2 injection. The main objective of my thesis is to examine and identify the analytical approaches in modeling of pressure profile during CO2 injection. It includes single injection as well as multiple wells injection scenarios. The second case is much more important from practical point of view and applicability of analytical tools should be validated. Two models of injection/production are considered: (i) Single-phase (brine production from a brine reservoir) and (ii) Two phase model (CO2 injection in a brine reservoir). In both cases, we analyzed the pressure build-up and discussed the results in comparison with numerical simulations. We also present a sensitivity analysis of the reservoir parameters on CO2 sequestration. The second part of the thesis focuses on finding ways to increase the CO2 injection capacity of saline aquifers by using the technique of multiple wells injection strategy. Numerous test cases will be presented to optimize the well placement and number of wells to get the maximum sequestration. The thesis will look upon the different ways to maintain the reservoir pressure below fracture pressure such as optimization of injection wells, varying the flow-rates of injection wells and by placement of relief wells to produce brine from the reservoir.

Download or read book Model Selection for CO2 Sequestration Using Surface Deflection and Injection Data written by Chiazor Nwachukwu and published by . This book was released on 2015 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: In recent years, sequestration of CO2 in the subsurface has been studied more extensively as an approach to curb carbon emissions into the atmosphere. Monitoring the fate and migration of the CO2 plume in the aquifer is of utmost interest to regulators and operators. Current monitoring techniques like time-lapse seismic are expensive and have limited applicability. Moreover, these techniques have little predictive value unless embedded within a feedback-style control scheme. Provided that field data such as bottom-hole pressures, well rates, or even surface deformation is available, geologic models for the aquifer can be created and used, as an input to a flow simulator, to predict the migration of CO2. A history matching approach has been developed, within a model selection framework, to select and refine geologic models within a selected set of models until they represent the spatial heterogeneity of the target aquifer, and produce forecast with relatively small uncertainty. An initial large suite of models can be created based on prior information of the aquifer. Predicting the response from these models however, presents a problem in terms of computational time and expense. A particle-tracking algorithm has been developed to estimate the flow response from geologic models, while significantly reducing computational costs. This algorithm serves as a fast approximation of finite-difference flow simulation models, and is meant to provide a rapid estimation of connectivity of the aquifer models. A finite element method (FEM) solver was also developed to approximate the geomechanical effects in the rock caused by the injection of CO2. The approach used here utilizes a partial coupling scheme to sequentially solve the flow and geomechanical equilibrium equations. The validity of the proxies is tested on both 2D and 3D field cases, and the solutions are shown to correlate reasonably well with full-physics simulations. We also demonstrate the application of the model selection algorithm to a 3D reservoir with complex topography. The algorithm includes three main steps: (1) predicting the flow and geomechanical response of a large prior ensemble of models using the proxies; (2) grouping models with similar responses into clusters using multidimensional scaling together with a k-means clustering approach; and (3) selecting a model cluster that produces the minimum deviation from the observed field data. The model selection procedure can be repeated using the sub-group of models within a selected cluster in order to further refine the forecasts for future plume migration. This entire iterative model selection scheme is demonstrated using the injection data for the Krechba reservoir in Algeria, which is an active site for CO2 sequestration.

Download or read book Utilizing Distributed Temperature Sensors in Predicting Flow Rates in Multilateral Wells written by Jassim Mohammed A. Al Mulla and published by . This book was released on 2012 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: The new advancement in well monitoring tools have increased the amount of data that could be retrieved with great accuracy. Downhole pressure and temperature could be precisely determined now by using modern instruments. The new challenge that we are facing today is to maximize the benefits of the large amount of data that is being provided by these tools and thus justify the investment of more capital in such gadgets. One of these benefits is to utilize the continuous stream of temperature and pressure data to determine the flow rate in real time out of a multilateral well. Temperature and pressure changes are harder to predict in horizontal laterals compared with vertical wells because of the lack of variation in elevation and geothermal gradient. Thus the need of accurate and high precision gauges becomes critical. The trade-off of high resolution sensors is the related cost and resulting complication in modeling. Interpreting measured data at real-time to a downhole flow profile in multilateral and horizontal wells for production optimization is another challenge. In this study, a theoretical model is developed to predict temperature and pressure in trilateral wells based on given flow conditions. The model is used as a forward engine in the study and inversion procedure is then added to interpret the data to flow profiles. The forward model starts from an assumed well flow pressure in a specified reservoir with a defined well structure. Pressure, temperature and flow rate in the well system are calculated in the motherbore and in the laterals. These predicted temperature and pressure profiles provide the connection between the flow conditions and the temperature and pressure behavior. Then we use an inverse model to interpret the flow rate profiles from the temperature and pressure data measured by the downhole sensors. A gradient-based inversion algorithm is used in this work, which is fast and applicable for real-time monitoring of production performance. In the inverse model, the flow profile is calculated until the one that generates the matching temperature and pressure profiles in the well is identified. The production distribution from each lateral is determined based on this approach. At the end of the study, the results showed that we were able to successfully predict flow rates in the field within 10% of the actual rate. We then used the model to optimize completion design in the field. In conclusion, we were able to build a dependable model capable of predicting flow rates in trilateral wells using pressure and temperature data provided by downhole sensors.

Download or read book An Analytical Pressure Model to Guide Downhole Sensor Placement for Carbon Dioxide Sequestration Monitoring written by Yilin Mao and published by . This book was released on 2014 with total page 77 pages. Available in PDF, EPUB and Kindle. Book excerpt: "Injecting CO2 into saline aquifers is currently the most viable approach to mitigate global greenhouse gas effect. Various monitoring techniques are required to achieve 99% accuracy in determining the location of the injected CO2 plume. Sensor locations are critical to the monitoring quality necessary to meet this requirement but have scarcely been discussed. The pressure profile needs to be modeled accurately at the initial stage of CO2 injection to guide sensor locations. The objective of this thesis was to develop an analytical solution for CO2 sequestration based on time and distance. This will guide the locations of downhole pressure sensors and optimize the sensor density. This work establishes a comprehensive pressure model, in which three flow regimes were fitted on sequences of time domain in each boundary condition, assuming a radial and homogenous saline aquifer. The model includes transient and pseudo steady- state flows to solve early time pressure. The flow front equation divides the aquifer into two flow regions. The analytical solution that applied to two field cases was compared and confirmed with the results from reservoir simulations. Sensitive analyses were performed on major aquifer parameters. The application of this work was to determine downhole pressure sensor locations. Distributed pressure sensors have the potential to be implemented in CO2 sequestration operations with a moderate cost. Sensor ranking was optimized by an error weighting matrix based on a covariance matrix and experimental measurement distribution in this work. Sensor placement was guided through regression analysis performed on two flow regions. With the input of sensor physical errors, various ranges of monitoring accuracy can be achieved with different sensor placement densities."--Abstract, page iii.