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Collaborating Authors
Formation Evaluation & Management
Abstract The efficiency of the enhanced-coalbed-methane (ECBM) and CO2 sequestration process depends on the wettability behavior of the coal-water-CO2 system. It depends on the CO2 diffusion rate from the cleat network, through the micro-cleats, to the surface of the coal matrix. If the coal is hydrophobic, the gas will fill the smaller pores, which leads to faster diffusion of CO2 to the coal surface (diffusion coefficient of CO2 = 1.7*10 m/s at 100 bar and 300 K). The diffusion coefficient decreases to 2*10 m/s at the hydrophilic system. This paper interoperates the published experimental outcomes of coal wettability at varies range of pressure, temperature, and gas composition. Wettability studies usually used contact angle measurements as a simple method to characterize the coal. Adsorption isotherm, Zeta potential measurements were used to interoperate the contact angle results and understand the wettability behavior. Recently, Fourier Transform Infrared Spectrometer (FTIR) technique was employed to investigate the functional chemical groups of the oxidized coals. Coal has different ranks with different oxygen-containing polar groups such as carboxyl (COOH), hydroxyl (OH), and methoxyl (OCH3) groups. Coal becomes more water-wet with decreasing rank, carbon content and with increasing oxygen-containing groups. Regardless of the coal rank, the coal becomes more CO2-wet with increasing pressure up to the critical gas conditions where the coal wettability slightly increases. As the water-salt concentration increases, it compresses and destabilizes the double-layer surrounding the coal surface, causing a reduction in the absolute zeta potential value and making the coal surface more hydrophobic. The temperature has a negative effect on CO2 wettability to coal and the coal becomes more hydrophilic with increasing the temperature. In oxidized coal surfaces, FTIR technique is more sensitive than contact angle measurements.
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
The Development of CO2 Plume in CO2 Sequestration in the Aquifer
Fu, Hao (University of North Dakota, Grand Forks) | Long, Yifu (Missouri University of Science and Technology) | Wang, Sai (University of North Dakota, Grand Forks) | Wang, Yanbo (University of North Dakota, Grand Forks) | Yu, Peng (Beibu Gulf University, Qinzhou) | Ling, Kegang (University of North Dakota, Grand Forks)
Abstract Geological carbon sequestration through injecting large-scale carbon dioxide (CO2) into the deep saline aquifers represents a long-term storage of CO2. In the CO2 sequestration process, the injected CO2 is displacing water from the injection point and is expected to remain in the reservoir. Due to the nature of one phase displacing another phase in porous media, it is noted that different water saturation exists in the CO2 plume during the displacement. Water distribution in the plume will affect the size of the plume subsurface. Furthermore, the gravitational segregation between CO2 and water will cause overriding-tonguing during the injection and impact the shape of plume. To better understand the CO2 movement underground and development of CO2 plume, it is necessary to take the two-phase flow and gravity force effects into account when evaluating CO2 displacing water. The displacement of water by injecting CO2 is not a piston-like process in aquifer. Because water is the wetting phase and CO2 is the non-wetting phase when two phases flow in reservoir, water occupies the surface of matrix and small pores while CO2 resides in large pores and centers of pores. As a result, various water saturations distribute behind CO2 front during the displacement. The distribution is a function of fluid and rock properties, fluid-rock interaction, and injection operation. In this study, these factors are considered when developing new models to predict CO2 plume evolution during injection. Mass conservation, multiphase flow, and equation-of-states are applied in the derivation of the models, which guarantees a rigorous approach in the investigation. The modeling results indicate that CO2 does not displace water completely away from the plume. The shape of the CO2 front is controlled by the relative permeability of two phases and capillary pressure. Water saturation profile from CO2 injecting point to the displacement front shows that water saturation behind the CO2 front increases outwardly, and the change in saturation is non-linear. The injection rate impacts the sharpness of the CO2 front, thus leads to different gas plume sizes for same injection volume. The outward movement of the CO2 front decelerates as injection time goes on. The research illustrates that injection experiences two stages: transient and steady-state, in which the displacement behavior and the development of gas plume vary. Although the duration of transient stage is dictated by size of aquifer and is relatively short comparing with steady-state stage, its influence on the development of CO2 plume cannot be neglected when selecting gas compressor horsepower and determining injection rate.
- Asia (0.68)
- North America > United States > Kansas (0.46)
- North America > United States > North Dakota (0.28)
- North America > United States > Kansas > Dickman Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabamun Formation (0.97)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Abstract A fault is a potential pathway for fluid leakage, which can contaminate underground water resources. In addition, fault leakage can affect hydrocarbon production. This study aims to develop a type-curve-based methodology to characterize a fault both laterally and vertically using pressure transient analysis. We develop an analytical model to assess the pressure perturbations corresponding to production/injection from/into a reservoir with a leaky fault. Displacement of layers during the fault displacement may cause alteration of the reservoir properties across the fault. This alteration is accounted for by considering different properties on the two sides of the fault. The reservoir is divided into two regions separated by the fault, which are in hydraulic communication with one another and with the overlying/underlying permeable layers. The governing system of differential equations and corresponding boundary conditions are solved using Fourier and Laplace transforms. At early times of the fault leakage, the recorded well pressure changes are mostly affected by the fault properties and the effects of resistance from the upper zone emerge later. In this model, we neglect the resistance to leakage flow caused by the overlying zone to focus on the pressure changes at early times of the fault leakage. We show that these assumptions are valid to arrive at correct fault characteristics. For fault characterization, type curves are presented in terms of dimensionless vertical and horizontal conductivities of the fault. A computational optimization method is used in combination with type curves to fully characterize the reservoir-fault system. Results show that the characterization method is useful to estimate the fault vertical and lateral conductivities.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
Abstract Carbon dioxide is commonly injected during secondary or tertiary recovery to enhanced oil recovery. While CO2 can also cause some precipitation damage. Usually scale ions (Ca, Mg) in water react with CO2 to form solid precipitation that can plug the pores. In this report, CO2 is injected into the high salinity formation water, which makes the problem of inorganic precipitation by reaction with scale ions. A number of static experiments have been conducted about various reservoir pressures and temperatures when the pH and scale ions content changes in a high temperature high pressure Reactor. Thus, the aim of this report is to determine how the presence of inorganic precipitation during CO2 injections and the factors affecting the amount of CO2 with high salinity water generating inorganic precipitation. Results from XPS and SEM images of precipitation are also provided. The results indicate that there are three stages in the reaction between carbon dioxide and high salinity formation water, and the third stage with high temperature or low pressure produced precipitation is the most important. PH less than 7 can still produce precipitation. The larger the PH and the scale of the ion content, the more precipitation; at first with low temperature or high pressure, and then with the high temperature or low pressure produced the largest amount of precipitation. 1. Introduction CO2 flooding technology is an important technology developed in the 1980s, which has been widely paid attention to by all countries in the world [1]. However, compared with oil, gas and other geologic fluids, CO2 is an active gas, and when it was injected into the ground, it is very easy to react with the formation of fouling ions in stratum water to produce precipitation and eventually change the physical and chemical properties of the reservoir [2]. Especially, the change of reservoir permeability will seriously affect the underground storage capacity of CO2 [3], so it is necessary to study and discuss the CO2 and formation water interaction.
- Geology > Geological Subdiscipline (0.70)
- Geology > Rock Type > Sedimentary Rock (0.47)
- North America > United States > Wyoming > Big Horn Basin > NPR-3 > Tensleep Formation (0.99)
- North America > United States > Louisiana > Downdip Tuscaloosa-Woodbine Trend Basin > Tuscaloosa Formation (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract The close proximity of large CO2 emitters and depleted oil and gas reservoirs in the Louisiana Chemical Corridor (LCC) provide unique opportunities for CO2 geological sequestration in coastal Louisiana. The identification of sites with good storage capacity and retention characteristics is of prime importance for successful CO2 storage projects. In this study, the Bayou Sorrel field area located within close proximity of some of the large CO2 emitters in the LCC, is analyzed as a potential candidate site for aquifer storage. The results of static and dynamic aquifer storage capacity estimates are presented in this study. A volumetric approach is used to estimate the static storage capacity, and reservoir simulations are performed to compute dynamic storage capacity. The field and well data from publically available data sources are compiled to characterize the sands for prospective CO2 sequestration intervals (i.e., non-productive sands), and pressure and temperature conditions. Information of total areal extent, gross formation thickness, and total porosity are used along with a storage efficiency factor to find the pore volume available for storage. The upper depth limit for CO2 injection is dictated by the pressure and temperature conditions at which CO2 exists in a supercritical state. The Peng-Robinson (PR) equation of state is used in conjunction with subsurface pressure and temperature to determine the minimum depth at which CO2 is supercritical. Multiple geological realizations are used for a realistic site specific storage capacity estimate. The reservoir simulations capture the transient nature of the process and provide estimation of storage capacity under dynamic conditions. The sensitivity of injection location and boundaries is also evaluated in the dynamic storage capacity estimates. The results of the dynamic storage capacity estimate for a 1,000 ft thick interval at an average depth of 7,100 ft show that reasonable values of storage efficiency factors for this region are in the range of 1.14 to 2%. The results of the dynamic model also show that the nature of the storage zone boundary type, end point saturation and injection rate play significant role in estimation of dynamic storage capacity. These factors may induce more than 30% change in estimated dynamic storage value. The calculated storage efficiency factor may be applicable to other potential sites in this region, having similar geological characteristics.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.94)
Abstract Fluids are injected in subsurface permeable formations for various purposes including waste disposal, gas storage, CO2 sequestration, and enhanced oil/gas recovery. Containment of the injected fluids is needed to meet the regulatory requirements and/or to ensure efficiency of the intended processes. The injected fluids can leak to overlying formations in presence of leakage pathways. Improperly plugged and abandoned (P&A) wells are considered as the main potential leakage pathways. In a previous work, we introduced a vertical pressure transient interference test and presented an analysis methodology to detect and characterize leaking wells. The analysis methodology was based on an inverse modeling algorithm that can be highly instable and computationally expensive. Here, we propose an easy-to-use fully graphical methodology to characterize leaking wells. The pressure measurements are graphed in three different forms. The slopes and intercepts of the line-fitted graphs are used to determine the leak location and transmissibility as well as the transmissivity ratio of the connected zones. The graphical method is applied to an example problem to illustrate its application procedure and effectiveness. Introduction The Leakage through abandoned wells and improperly plugged boreholes can create vertical communication between otherwise hydrologically isolated permeable zones. The driving mechanism behind the leakage can be the hydraulic gradients created by injection into one of the zones. Zeidouni and Pooladi-Darvish (2012a, 2012b) introduced a vertical interference test to detect and characterize a leaking well connecting the operating zone to an overlying non-operating zone which is otherwise separated by a sealing caprock. The test involves injection (production) into (from) the operating zone (OZ) and observing the pressure at a distance both in the OZ and the monitoring zone (MZ). We use injection throughout this paper for consistency. Several researchers attempted to analyze the pressure observations through inverse modelling approach and data assimilation (Wang and Small 2014, Jung, Zhou, and Birkholzer 2013, Sun et al. 2013, Zeidouni and Pooladi-Darvish 2012a, b, Chabora and Benson 2009, Jung, Zhou, and Birkholzer 2015, Keating et al. 2014). While inverse modeling can be very useful, it requires robust and computationally expensive inversion techniques that may not be easy to implement in practice. Also, inverse models can be very instable if the unknown parameters are not fully independent. It would be useful to develop graphical approaches such as those used in conventional pressure transient analysis that can be conveniently used in analyzing the pressured data for leaking well characterization.
Preliminary studies have been done to characterize rock-fluid properties, and flow mechanisms in the shale reservoirs. Most of these studies, through modifying methods used for conventional reservoirs, fail to capture dynamic features of shale rock and fluids in confined nano-pore space. In unconventional reservoirs, interactions between the wall of shale and the contained fluid significantly affect phase and flow behaviors. The inability to model capillarity with the consideration of pore size distribution characteristics using commercial software may lead to an inaccurate oil production performance in Bakken. This paper presents a novel formulation that consistently evaluates capillary force and adsorption using pore size distribution (PSD) directly from core measurements. The new findings could better address differences in flow mechanisms in unconventional reservoirs, and thus lead to an optimized IOR practice. This paper presents a novel formulation that consistently evaluates capillary force with respect to pore size distribution (PSD) directly from Bakken core measurements. We also demonstrate how permeability would change as reservoir depletes, and more importantly CO2 huff-and-puff, and incorporate the new model to a 3D dynamic simulator. We further developed adsorption models using a local density optimization algorithm, to better address the incapability of Langmuir model for wet and liquid-rich formations. Our advances were also designed for multi-component interactions at adsorption sites for a full spectrum of reservoir pressures of interests. This new adsorption model, based on exactly the same physical chemistry principles at different pressures, revolved from monolayer at low pressure to more complex multilayer model spontaneously and consistently, imperative to CO2 cycling. With our advances in understanding key production mechanisms of capillarity and adsorption, we are able to differentiate production driving mechanisms in unconventional reservoirs vs. conventional ones. A new compositional simulator was developed that captures those differentiations and results show that should capillarity be consistently formulated with PSD, significant difference in production profile is observed. As shown for CO2 huff-and-puff process in unconventional reservoirs, a smaller amount of soaking time and a 30% higher in ultimate recovery was achieved, as compared with the case not considering capillarity and adsorption properly. This paper implements a novel formulation that captures capillarity pressure under pore confinement using a full spectrum of PSD characterization for shale oil core analysis. The new model consistently evaluates capillary adsorption effects for reservoir fluid density evolution using industrial accepted equation-of-state model and reservoir pressure depletion and CO2-IOR process. A substantial increase in oil production is illustrated when PSD, an important unconventional reservoir characteristics, is properly modeled. The new method may bring additional insight to greatly mitigate uncertainties for IOR potential evaluation, productivity and EUR assessment for unconventional reservoirs.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- (3 more...)
- Research Report > New Finding (0.86)
- Overview > Innovation (0.73)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Carbon dioxide (CO2) is injected into subsurface rocks either to improve hydrocarbon recovery or for permanent storage in geologic formations. At storage sites, CO2 injection wells are drilled and completed with multiple-string casings, which are cemented to the host rock. Cement is the primary means of protecting these casings from corrosive fluids and isolating storage zones from overlying fresh water aquifers by effectively sealing the casing-rock annulus. Over the life of the well, dissolved CO2 interacts with the casing-cement-rock system thereby degrading the hardened cement and resulting in loss of zonal isolation and structural integrity required to support the casing and to ensure long-term integrity of the well. Cement performance is often assessed through laboratory measurement of compressive strength, porosity and permeability. These parameters are indicators of mechanical integrity. Although compressive strength in the range of 0.7 to 5 MPa is generally sufficient to continue drilling after the casing is cemented, further hydration and chemical degradation occur throughout the operational life of the well. In CO2 injection wells, environmental conditions (i.e. CO2 concentration, pressure and temperature) around the cement result in further alteration in mechanical properties. This hostile environment causes severe mechanical damage and ultimate failure of cement sheath, potentially leading to micro-channelling and formation of micro-annuli. In this study, experiments were conducted to investigate the effect of CO2 concentration on mechanical integrity of well cements (Classes G and H) after exposure to carbonic acid environment. Cement cores were prepared and aged for 14 days in autoclave filled with 2% NaCl solution saturated with methane gas containing carbon dioxide. Aging tests were performed at 38°C and 42 MPa, varying CO2 concentration. To assess the level of degradation and describe the process of acid attack, compressive strengths of unexposed and exposed specimens were measured and compared. In addition, other properties of cement cores including porosity, permeability, stiffness/elasticity and Fourier Transform Infrared Spectroscopy (FTIR) measurements were obtained and used in the assessment. After 14 days of exposure, increase in CO2 concentration leads to insignificant changes in compressive strength due to combined effect of carbonation of cement hydrates (calcium silicate hydrates and calcium hydroxide) and subsequent leaching, with each process compensating for the other. Porosity, permeability and FTIR measurements are consistent with this observation. Under the experimental conditions adopted in this study, durability of Classes G and H cement are comparable. However, Class H cement becomes more elastic (i.e. less stiff) than Class G cement as CO2 concentration increases. FTIR mineralogy provides evidence that the mechanical behaviour of well cement after exposure to CO2-saturated brine is a direct consequence of interconnected chemical processes. Under carbon sequestration conditions, these processes counterbalance one another to ensure long-term integrity of the well for CO2 storage and containment.
- North America > United States > Texas (1.00)
- Asia (0.68)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Geology > Geological Subdiscipline > Mineralogy (0.67)
- North America > United States > Wyoming > La Barge Field > Madison Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Hugin Formation (0.99)
- (36 more...)
Abstract A novel pathway for the high energy efficiency production of metal from metal oxide via electrolysis in ionic liquids at low temperature was investigated. Metals such as Cu, Zn, and Pb are normally produced by the application of very high temperatures. The main goal is to eliminate the use of carbon and high temperature application in the reduction of metal oxides to metals. Experimental results for electrochemical extraction of Zn from ZnO using Urea ((NH2)2CO) and Choline chloride (HOC2H4N(CH3)3+Cl-) or (ChCl) in a molar ratio 2:1, constant voltage at 85°C is discussed. Solubility of ZnO in solution was measured using FTIR and ICP. Electrolysis experiments were conducted using EG&G potentiostat/galvanostat with three electrode cell systems. The deposits were characterized using XRD and SEM. The results showed that pure zinc metal was deposited on the cathode. Successful extraction of zinc metal from zinc oxide dissolved in Urea/ChCl (2:1) was accomplished. This technology will advance the metal oxide reduction process by reducing the energy consumption and also eliminating the production of CO2 which makes this an environmentally benign technology for metal extraction. INTRODUCTION Ionic liquids (ILs) are organic salts that are liquids over a wide temperature range, including room temperature. They are considered as new generation solvents, which are capable of replacing volatile organic compounds that are traditionally used as industrial solvents. The important properties of ionic liquids include wide electrochemical window, high ionic conductivity, almost non-volatile, non-flammable, corrosion resistance to plastics and carbon steels, high thermal stability, wide temperature range for liquid phase, and high solvating capability. These properties offer significant advantages in the design and performance of metal extraction processes [1]. The wide electrochemical window (~ 4 V) of ionic liquids also enables the possibility of extracting reactive metals or alloys which would be very difficult in aqueous solvents. Chloroaluminate ionic liquids such as 1-butylpyridinium chloride (BuPyCl-AlCl3) and 1-ethyl-3-methylimidazolium chloride (EMIC-AlCl3) systems have been successfully used as the electrolytes for metal electro-deposition [2–5]. The thermo-physical properties of chloride based (C2mimCl, C4mimCl, C6mimCl) and fluoride based ionic liquids (CnmimPF6, CnmimBF4) were investigated [6, 7]. A comprehensive review was made on extraction of metals and alloys using ionic liquids [1]. Several investigations have been carried out on extraction of metals from its chlorides using low temperature ionic liquids. To use chlorides as the starting material adds an additional step when considering an industrial operation wherein the metal oxides need to be converted to chlorides, only then it can be dissolved in an ionic liquid. Metal oxides are not readily dissolved in ionic liquids.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.77)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.60)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.52)
Abstract A novel, cost-saving approach combining advanced electronic and chemical technologies for rapidly acquired reservoir flow measurements and early-alteration of flows is described. The combined technologies improve CO2 injection, leak detection, and reservoir flow management in offshore CO2 enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. The approach is based on old and new technologies that have been field-proven in land-based operations. It employs reservoir flow-induced micro-deformation measurements by tiltmeters and absolute seafloor position monitoring using global positioning systems combined with underwater acoustic distance measurements from the sea surface to instruments installed in the seafloor over offshore reservoirs. These systems can acquire micro-deformation data, which allows for geomechanical inversion analysis to provide 3-D reservoir flow images. Real-time temperature, pressure, and other data from fiber-optic sensors may also be needed to better characterize some CO2 flows. New flow-controlling and leak-sealing chemical systems and placement methods combined with conventional ones have improved the options for management of flow paths both inside and outside of offshore reservoirs. The paper includes a discussion on how the monitoring technology has evolved from similar methods proven in EOR projects, and more recently in CCS projects, to identify reservoir flows and pinpoint abnormal ones. An example of normal CO2 flow results is presented to show how operators can calibrate flow-prediction software models and make fast decisions to apply flow enhancing methods that improve CO2 sweep efficiency, increase oil production, and better utilize reservoirs' CO2 storage capacity. Another example shows the early identification of an abnormal-flow path location that enables operators to make timely selections of sealing methods and materials to eliminate unwanted flows inside or outside of reservoirs and ensure planned CO2 plume movement and containment within reservoirs. The CO2 flow controlling and remediation technology's history of field proven success is described along with the recently developed versions. Generic case histories of conventional methods on land vs. the proposed offshore systems are compared to show how the new approach creates synergy that can improve the performance of offshore CO2 EOR and CCS projects while reducing operating costs.
- North America > Canada (0.68)
- Europe (0.68)
- North America > United States > Texas (0.67)
- North America > United States > California (0.67)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.93)
- North America > Canada > British Columbia > Peace River Field (0.99)
- Africa > Middle East > Algeria > Tamanrasset Province > Ahnet-Timimoun Basin > Krechba Field (0.99)
- Africa > Middle East > Algeria > Ghardaia Province > Ahnet-Timimoun Basin > Krechba Field (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)