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Collaborating Authors
Results
Comprehensive Evaluation of a Novel Recrosslinkable Hyper Branched Preformed Particle Gels for the Conformance Control of High Temperature Reservoirs
Song, Tao (Missouri University of S & T) | Ahdaya, Mohamed (Missouri University of S & T) | Zhao, Shuda (Missouri University of S & T) | Zhao, Yang (Missouri University of S & T) | Schuman, Thomas (Missouri University of S & T) | Bai, Baojun (Missouri University of S & T)
Abstract The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of water or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures due to the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyper-branched re-crosslinkable preformed particle gel (HT-BRPPG) designed for North Sea high-temperature reservoirs (130 °C), which can re-crosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability and plugging performance of the HT-BRPPG. Bottle tests were employed to test the swelling kinetic and re-crosslinking behavior. High-pressure resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for over one year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could re-crosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130 °C. The elastic modulus of the re-crosslinked gel can reach up to 830 Pa with a swelling ratio of 10. In addition, the HT-BRPPG with a swelling ratio of 10 has been stable for over 15 months at 130 °C so far. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 387.9 psi/ft. Therefore, this novel BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.
- Europe > Norway > North Sea (0.34)
- Europe > United Kingdom > North Sea (0.25)
- Europe > North Sea (0.25)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock (0.88)
- Geology > Geological Subdiscipline (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Europe > United Kingdom > North Sea > Central North Sea > Utsira High > PL 006 > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract Wettability alteration considered as the principal mechanism has attracted more attention for low salinity waterflooding effect. It was significantly affected by electrokinetic interactions, which occurred at the interfaces of rock/brine and crude oil/brine. The mineral impurities of natural carbonate releasing ions have an important impact on the electrokinetics, which could lead to wettability shift subsequently. In this study, the effect of dolomite and anhydrite as the main impurities in natural carbonate, which caused wettability alteration, was evaluated using triple-layer surface complexation and thermodynamic equilibrium models coupled with extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The electrokinetics of crude oil and carbonate in brines were predicted by the triple-layer surface complexation model (TLM) based on zeta potential, while thermodynamic equilibrium model was mainly used for analyzing the carbonate impurities on wettability alteration. The equilibrium constants of reactions were determined by successfully fitting the calculated zeta potentials with measured ones for crude oil and carbonate in different solutions, which were validated for zeta potential prediction in smartwater. The disjoining pressure results show that there is a repulsion between crude oil and carbonate in Na2SO4 brine (Brine3) or smartwater (Brine4) equilibrating with calcite when comparing to that in MgCl2 (Brine1) and CaCl2 (Brine2), indicating the water-wet condition caused by the presence of sulphate ions. Moreover, the equilibrium of carbonate impurities with smartwater increases the repulsion between oil and carbonate. When the sulphate ion concentration in the adjusted smartwater exceeds a certain value, the effect of carbonate impurities on wettability alteration is not significant. Finally, the influence of smartwater pH on the interaction between oil and carbonate was evaluated with or without considering the equilibrium of carbonate impurities.
- North America > United States (0.68)
- Europe (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Sulfate (0.79)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.51)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Mobility Of Microemulsions: A New Method to Improve Understanding and Performances of Surfactant EOR
Rousseau, David (IFP Energies nouvelles - The EOR Alliance) | Le Gallo, Clémence (IFP Energies nouvelles - The EOR Alliance) | Wartenberg, Nicolas (Solvay - The EOR Alliance) | Courtaud, Tiphaine (Solvay - The EOR Alliance)
Abstract The mobility of Winsor III microemulsions, which can form in reservoirs when a surfactant formulation contacts oil, has become a critical parameter for feasibility evaluations of surfactant flooding EOR. The reason is that these bicontinous phases with low mobility are likely to impair the sweep efficiency of the remobilized oil. The common procedures to evaluate microemulsion's mobility are based on viscosity measurements. As they involve rheometers, namely pure shear flows, and conditions where microemulsions are separated from the water and oil phases they should remain equilibrated with, they are not satisfactory. We present a new method to directly determine the mobility of microemulsions at equilibrium and in-situ, namely when flowing in porous media. The method consists in preforming the Winsor III microemulsion in a buffer cell and then injecting it in a small sized core plug. The bicontinous phase stays at equilibrium because the oil and water phases, present in the buffer cell, remain in contact with it. The mobility is assessed through the resistance factor (or mobility reduction factor), relative to the water phase injected first. This observable accounts for both viscosity and potential permeability impairment effect. As it directly represents the reduction of the mobility of the water phase, it is representative of phenomena taking place in the reservoir. During a typical experiment, the same microemulsion is also injected in a capillary tube, in order to determine its viscosity in a pure shear flow. Winsor III microemulsions were injected in sandstone plugs of three different permeabilities (1700 to 45 mD), and in a 170 mD carbonate plug. The first outcomes are that the resistance factors in the porous media and capillary relative viscosities have a marked shear-thinning behavior but are always of the same order of magnitude. This indicates that the flow of microemulsions entails no or little permeability impairment. Based on the experimental determination of the porous media's shape factors, the resistance factors and capillary viscosity data were also plotted against the equivalent wall shear rate. For the highest permeability sandstone, the capillary and porous medium data scaled almost perfectly, showing that, in this case, the microemulsion's transport properties are that of an ideal non-Newtonian fluid. However, increasing deviations were observed when decreasing the sandstone permeability as well as for the carbonate porous medium. This suggests that microemulsions are strongly affected by the composite deformations taking place in complex microscopic pore structures. These outcomes show the importance of determining the microemulsion-induced resistance factor in representative conditions in order to forecast for the impact of microemulsion's mobility in reservoirs. Furthermore, the method proposed can be applied to investigate close to optimum conditions as well as to study the propagation of microemulsions.
- Research Report (1.00)
- Overview > Innovation (0.60)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Reaction Kinetics Determined from Core Flooding and Steady State Principles for Stevns Klint and Kansas Chalk Injected with MgCl2 Brine at Reservoir Temperature
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, 4021 Norway) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger, 4021 Norway) | Olsen, Andre Tvedt (Department of Energy Resources, University of Stavanger, 4021 Norway) | Bukkholm, Erik (Department of Energy Resources, University of Stavanger, 4021 Norway)
Abstract A methodology is presented for determining reaction kinetics from core flooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core a defined period and then is flushed out. The residence time and produced brine composition is compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady state data are directly comparable to equilibrating the injected brine gradually with time and does not require spatial and temporal modeling of the entire dynamic experiments. Each steady state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment. Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint chalk from Denmark, and Kansas chalk from USA. The reaction kinetics of chalk are important as oil-bearing chalk reservoirs are chemically sensitive to injected seawater. The reactions can alter wettability and weaken rock strength which has implications for reservoir compaction, oil recovery and reservoir management. The temperature was 100 and 130°C (North Sea reservoir temperature). The rates during flooding were varied from 0.25 to 16 PV/d while shut-in tests provided equivalent rates down to 1/28 PV/d. The results showed that Ca ions were produced and Mg ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order and equilibrium constant) was implemented together with advection to analytically calculate steady state effluent concentrations when injected composition, injection rate and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady state data could be fitted efficiently. From data trends, the parameters were determined relatively accurate for each core. The roles of reaction parameters, pore velocity and dispersion were illustrated with sensitivity analyses. The steady state method allows computationally efficient matching even with complex reaction kinetics. Using a comprehensive geochemical description in the software PHREEQC, the kinetics of calcite and magnesite mineral reactions were determined by matching the steady state concentration changes as function of (residence) time. The simulator predicted close to identical production of Ca as loss of Mg. The geochemical software predicted much higher calcite solubility in MgCl2 than observed at 100 and 130°C for Stevns Klint and Kansas.
- Europe (1.00)
- North America > United States > Kansas (0.91)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.66)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Phase Behavior and Minimum Miscibility Pressure of Confined Fluids in Organic Nanopores
Song, Yilei (China University of Petroleum, Beijing) | Song, Zhaojie (China University of Petroleum, Beijing) | Liu, Yueliang (China University of Petroleum, East China) | Guo, Jia (China University of Petroleum, Beijing) | Bai, Baojun (Missouri University of Science and Technology) | Hou, Jirui (China University of Petroleum, Beijing) | Bai, Mingxing (Northeast Petroleum University) | Song, Kaoping (China University of Petroleum, Beijing)
Abstract Phase equilibrium of shale fluid is highly disturbed due to liquid adsorption and capillary pressure in densely-developed organic nanopores. And the miscibility phenomenon between gas and oil is also changed during gas injection for enhanced oil recovery (EOR). Therefore, it is imperative to develop a general framework of theoretical models and algorithm to investigate the effect of pore proximity on phase behavior and miscibility of confined fluids in shale formations. In this study, first, an improved vapor/liquid equilibrium (VLE) calculation model is presented to calculate the phase behavior of confined fluids based on our modified Peng-Robinson equation of state (A-PR-EOS) which can reflect the effect of adsorption. The capillary pressure across the interface and the critical property shift of pure component are also taken into account. An improved Young-Laplace equation is utilized to simulate capillarity and the shifted critical properties can be obtained using the A-PR-EOS. Then, a prediction process for the phase behavior of a quaternary mixture (CO2, CH4, n-C4H10, n-C10H22) is performed, and the results are compared against the experimental data from previous literature, yielding an average error of 1.29%. Results indicate that the presence of nanopore confinement could decrease the density difference between the liquid and vapor phase of the quaternary mixture, and thus induce the reduction of interfacial tension (IFT). As pore size becomes smaller, the IFT decreases rapidly, especially when the pore radius (Rp) is less than 20 nm. Furthermore, the vanishing interfacial tension (VIT) algorithm and the modified VLE procedure are applied to determine the minimum miscibility pressure (MMP) of Bakken shale oil with CO2. The MMP is reduced from 20.2 MPa at 50 nm pores to 17.5 MPa at 20 nm pores. Hence, the reduction of pore size leads to a decrease in MMP, i.e. the CO2 and the reservoir fluid could reach miscibility at a lower pressure, which is beneficial for CO2-EOR. The proposed model could provide a consistent description of fluid phase behavior over the whole range of pore sizes in the Bakken, and could be applied to guide the development of shale hydrocarbon reservoirs, such as reserves and production estimates.
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract This paper introduces a new approach for using solvents for enhanced oil recovery from organic-rich unconventional reservoirs. The heavy organic components in the reservoir rock, i.e. bitumen, are included in the phase behavior model using a cubic equation-of-state. The phase behavior of mixtures of methane, CO2, and dimethyl ether (DME) with reservoir hydrocarbons including bitumen was studied to better understand the interaction of each solvent with reservoir fluids including water in the case of DME. The phase behavior models were then used in an equation-of-state compositional reservoir simulator to explore the potential of each solvent to increase the oil recovery including otherwise immobile bitumen from a 3D heterogeneous reservoir.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (2 more...)
Abstract Current HLD-NAC theory and most simulators represent multicomponent mixtures with three lumped components, where the excess phases are also assumed pure. This can cause significant errors, and discontinuities in chemical flooding simulation for surfactant mixtures. We coupled the HLD-NAC and pseudo-phase models to develop an EOS for microemulsions where surfactant, polymer, alcohol, alkali and monovalent/divalent ions can partition differently into the excess phases and microemulsion phase as temperature and pressure are changed. We develop a pseudo-phase model to calculate partitioning of components between lumped components or namely pseudo-phases. The pseudo-phase model is based on a transformed composition space. The partitioning model is based on different mechanisms such as cation exchange like reactions for ions and surfactant hydration properties. Next, the three-pseudo-component HLD-NAC EOS is used to calculate curvature of the interface and microemulsion phase composition based on pseudo-phases. That is, the microemulsion phase consists of a curved ruled surface between water and oil pseudo-phases. Polymer partitioning is updated based on micelle radius. Finally, the phase compositions are converted back from pseudo-phase space to the original composition space. This model is the first comprehensive and mechanistic flash calculation algorithm based on HLD-NAC and pseudo-phase theory to calculate microemulsion properties for mixtures without the assumption of pure excess phases. This algorithm allows for modeling of the chromatographic separation of surfactant, soap, alcohol, alkali and polymer components in chemical flooding processes. Current microemulsion models usually ignore the differing partitioning of components between excess and microemulsion phases, generating discontinuities that slow computational time and adversely impact accuracy.
Estimation of Foam Flow Parameters for Local-Equilibrium Methods using Steady-State Flow Experiments and Optimization Algorithms
Cavalcante Filho, Jose Sergio (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract In this paper, we estimate foam parameters and investigate foam behavior for a given range of water saturation using two local equilibrium foam models: the population balance and the Pc*. Our method uses an optimization algorithm to estimate foam model parameters by matching foam measured pressure gradient from steady-state coreflood experiments. We calculate the effective foam viscosity and the water fractional flow using experimental data and we then compare lab data against results obtained with the matched foam models to verify the foam parameters. Other variables, such as the foam texture and foam relative permeability are used to further investigate the behavior of the foam during each experiment. We propose an improvement to the Pc* model with a better match in high quality regime by assuming resistance factor and critical water saturation is a linear function of pressure gradient. Results show that the parameter estimation method coupled with an optimization algorithm successfully matches the experimental data using both foam models. In the population balance, we observe different values of the foam effective viscosity for each pressure gradient due to variations of the foam texture and shear thinning viscosity effect. The Pc* model presents a constant effective viscosity for each pressure gradient; we propose the use of resistance factor and critical water saturation as a linear function of pressure to improve the match in the high quality regime, when applicable. Foam has been successfully used in the oil industry for conformance and mobility control in gas injection processes. The efficiency of a foam injection project must be assessed by means of numerical models. Although there are several foam flow models in the literature, the prediction of foam behavior is an important issue that needs further investigation.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Abstract In the case of surfactant EOR, an optimum formulation of surfactant has to be injected in the reservoir. This so-called optimum formulation corresponds to a minimum in the interfacial tension and a maximum in oil recovery and may be obtained with an appropriate balance of the hydrophobic and hydrophilic affinities of the surfactant. Salinity—scan tests are generally used to screen phase behavior of surfactant formulations before conducting time-consuming coreflood tests. The objective of this study was to develop a high-throughput dynamic microfluidic tensiometer, with the aim of studying interfacial phenomena between EOR injected formulations and crude oils and of optimizing chemical EOR processes for pilot or field applications. We have selected a method based on the Rayleigh-Plateau instability and the analysis of the droplets to jetting transition in a coaxial flow of two fluids. In fact, in coaxial flows, the transition between a droplet and a jetting regime depends on the velocities of each phase, the viscosity ratio, the confinement and the interfacial tension (IFT). As the three first parameters are known, the dynamic interfacial tension can be calculated. This microfluidic device has been specifically designed to support high temperatures (up to 150°C), high pressures (up to 150 bars) and is compatible with complex fluids such as crude oils and solutions of surfactants and polymers. The method was first developed and validated on a microfluidic device on model fluids at ambient temperature and atmospheric pressure for IFTs higher than 1 mN/m. It was then successfully applied for the measurement of IFTs over more than four decades. Measurements were also performed with a crude oil and a typical surfactant formulation. The validation of the HP/HT assembly, which has been designed with the aim to work in reservoir conditions, is currently under progress. By using this tensiometer, it would be quite easy to perform in short time numerous salinity scans on real systems in order to get the evolution of IFT and determine the optimal salinity S*.
- North America > United States (0.47)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)