Sequential Coupling of Geochemical Reactions With Reservoir Simulations for Waterflood and EOR Studies

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 469-484 ◽  
Author(s):  
Lingli Wei
Keyword(s):  
Water Chemistry ◽  
Oil Recovery ◽  
Reactive Transport ◽  
Produced Water ◽  
Mineral Dissolution ◽  
Individual Species ◽  
Chemical Changes ◽  
Injection Water ◽  
Geochemical Reactions ◽  
The Impact

Summary Many waterflood projects now experience significant amounts of water cut, with more water than hydrocarbon flowing between the injectors and producers. In addition to the impact on water viscosity and density that results from using different injection-water sources during a field's life, water chemistry itself may impact oil recovery, as demonstrated by recent research on low-salinity water-injection schemes. It is also known that water chemistry has a profound impact on various chemical enhanced-oil-recovery (EOR) processes. Moreover, the effectiveness and viability of such EOR schemes is strongly dependent on reservoir-brine and injection-water compositions. In particular, the presence of divalent cations such as Ca+2 and Mg+2 has a significantly adverse effect for chemical EORs. Using new developments in reservoir simulation, this paper outlines a method to couple geochemical reactions in a reservoir simulator in black-oil and compositional modes suitable for large-scale reservoir models for waterflood and EOR studies. The new multicomponent reactive-transport modeling capability considers chemical reactions triggered by injection water and/or injected reactive gases such as CO2 and H2S, including mineral dissolution and precipitation, cation exchange, and surface complexation. For waterflood-performance assessment, the new modeling capability makes possible a more-optimum evaluation of petrophysical logs for well intervals where injection-water invasion is suspected. By modeling transport of individual species in the aqueous phase from injectors to producers, reservoir characterization can also be improved through the use of these natural tracers, provided that the compositions of the actual produced water are used in the history matching. The simulated water compositions in producers can also be used by production chemists to assess scaling and corrosion risks. For CO2 EOR studies, we illustrate chemical changes inside a reservoir and in the produced water before and after CO2 breakthrough, and discuss geochemical monitoring as a potential surveillance tool. Alkaline-flood-induced water chemical changes and calcite precipitation are also presented to illustrate applicability for chemical EOR with the new simulation capability.

scholarly journals Impact of tailored water chemistry aqueous ions on foam stability enhancement

2021 ◽  
Author(s):  
Zuhair AlYousef ◽  
Subhash Ayirala ◽  
Majed Almubarak ◽  
Dongkyu Cha
Keyword(s):  
Aqueous Solutions ◽  
Water Chemistry ◽  
Foam Stability ◽  
Chloride Salt ◽  
Foam Generation ◽  
Monovalent Ions ◽  
Injection Water ◽  
Foam Stabilization ◽  
Aqueous Ions ◽  
The Impact

AbstractGenerating strong and stable foam is necessary to achieve in-depth conformance control in the reservoir. Besides other parameters, the chemistry of injection water can significantly impact foam generation and stabilization. The tailored water chemistry was found to have good potential to improve foam stability. The objective of this study is to extensively evaluate the effect of different aqueous ions in the selected tailored water chemistry formulations on foam stabilization. Bulk and dynamic foam experiments were used to evaluate the impact of different tailored water chemistry aqueous ions on foam generation and stabilization. For bulk foam tests, the stability of foams generated using three surfactants and different aqueous ions was analyzed using bottle tests. For dynamic foam experiments, the tests were conducted using a microfluidic device. The results clearly demonstrated that the ionic content of aqueous solutions can significantly affect foam stabilization. The results revealed that the foam stabilization in bulk is different than that in porous media. Depending on the surfactant type, the divalent ions were found to have stronger influence on foam stabilization when compared to monovalent ions. The bulk foam results pointed out that the aqueous solutions containing calcium chloride salt (CaCl2) showed longer foam life with the anionic surfactant and very weak foam with the nonionic surfactant. The solutions with magnesium chloride (MgCl2) and CaCl2 salts displayed higher impact on foam stability in comparison with sodium chloride (NaCl) with the amphoteric alkyl amine surfactant. Less stable foams were generated with aqueous solutions comprising of both magnesium and calcium ions. In the microfluidic model, the solutions containing MgCl2 showed higher resistance to gas flow and subsequently higher mobility reduction factor for the injection gas when compared to those produced using NaCl and CaCl2 salts. This experimental study focusing about the role of different aqueous ions in the injection water on foam could help in better understanding the foam stabilization process. The new knowledge gained can also enable the selection and optimization of the right injection water chemistry and suitable chemicals for foam field applications.

A Numerical Investigation of Low Salinity Polymer Flooding Effects from a Geochemical Perspective

2021 ◽  
Author(s):  
Omar Chaabi ◽  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Aqueous Phase ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Solution Chemistry ◽  
Related Effect ◽  
Exchange Reactions ◽  
Two Phase ◽  
Low Salinity ◽  
Geochemical Reactions

Abstract Low salinity polymer (LSP) flooding is getting more attention due to its potential of enhancing both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MRST was coupled with the geochemical software IPhreeqc. The effects of polymer were captured by considering Todd-Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to PHREEQC database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST-IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against PHREEQC for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

Geochemistry of Geological Hydrogen Storage in Sandstone Reservoirs

2021 ◽  
Author(s):  
Aliakbar Hassanpouryouzband ◽  
Katriona Edlmann ◽  
Mark Wilkinson
Keyword(s):  
Hydrogen Storage ◽  
Clean Energy ◽  
Pressure Change ◽  
Point Of View ◽  
Mineral Dissolution ◽  
Geological Storage ◽  
Before And After ◽  
Geochemical Reactions ◽  
Sandstone Reservoirs ◽  
The Impact

<p>To enable a fast transition of the global energy sector towards operation with 100% renewable and clean energy technology, the geological storage of hydrogen in depleted gas fields or salt caverns has been considered as a strong candidate for the future energy storage required for limiting global warming to well below 2 °C, as agreed under the Paris Agreement. As such, understanding the impact of injected hydrogen on the geochemical equilibrium in these storage reservoirs is critical. Here, using our bespoke high pressure/temperature batch reaction vessels we investigate the potential effects of hydrogen injection into 3 different sandstones reservoirs.  These experiments were conducted at reservoir temperature and at different injection pressures from 1 to 20 MPa with salinities from 0 to 10 weight% over different time periods from 1 to 8 weeks.  Our experiments reveal that there is no hydrogen-associated geochemical reaction for the selected sandstones. Although changing reservoir pressure slightly affected the mineral dissolution equilibria at ppm level for hydrogen injection scenarios, the fluctuations of mineral dissolution in water associated with pressure change have a negligible influence on the efficiency of geological hydrogen storage.  Therefore, based on the analysis of water chemistry before and after the mentioned experiments, we demonstrate that from geochemical point of view geological storage of hydrogen in these sandstone reservoirs is safe and we don’t expect any hydrogen loss due to geochemical reactions. </p>

Pore-scale hydrodynamic evolution within carbonate rock during CO2 injection and sequestration

2021 ◽  
Author(s):  
Chi Zhang ◽  
Siyan Liu ◽  
Reza Barati
Keyword(s):  
High Resolution ◽  
Reactive Transport ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Pore Scale ◽  
Modeling Framework ◽  
Calcite Dissolution ◽  
Potential Factors ◽  
The Impact

<p><span>The continuously rising threat of global warming caused by human activities related to CO</span><span><sub>2</sub> emission is facilitating the development of greenhouse gas control technologies. Subsurface CO</span><span><sub>2</sub> injection and sequestration is one of the promising techniques to store CO</span><span><sub>2</sub> in the subsurface. </span><span> </span><span>However, during CO<sub>2</sub> injection, the mechanisms of processes like injectant immobilizations and trapping and pore-scale geochemical reactions such as mineral dissolution/precipitation are not well understood. Consequently, the multi-physics modeling approach is essential to elucidate the impact of all potential factors during CO<sub>2</sub> injection, thus to facilitate the optimization of this engineered application.</span> </p><p><span>Here, we propose a coupled framework to fully utilize the capabilities of the geochemical reaction solver PHREEQC while preserving the Lattice-Boltzmann Method (LBM) high-resolution pore-scale fluid flow integrated with diffusion processes. The model can simulate the dynamic fluid-solid interactions with equilibrium, kinetics, and surface reactions under the reactive-transport scheme.  In a simplified 2D spherical pack, we focused on examining the impact of pore sizes, grain size distributions, porosity, and permeability on the calcite dissolution/precipitation rate. Our simulation results show that the higher permeability, injection rate, and more local pore connectivity would significantly increase the reaction rate, then accelerate the pore-scale geometrical evolutions. Meanwhile, model accuracy is not sacrificed by reducing the number of reactants/species within the system.</span></p><p><span>Our modeling framework provides high-resolution details of the pore-scale fluid-solid interaction dynamics. To gain more insights into the mineral-fluid interfacial properties during CO</span><span><sub>2</sub> sequestration, our next step is to combine the electrodynamic forces into the model. Potentially, the proposed framework can be used for model upscaling and adaptive subsurface management in the future. </span><span> </span></p>

Geochemical Modeling of Petrophysical Alteration Effect on CO2 Injectivity in Carbonate Rocks

2021 ◽  
Author(s):  
Fabio Bordeaux Rego ◽  
Shayan Tavassoli ◽  
Esmail Eltahan ◽  
Kamy Sepehrnoori
Keyword(s):  
Oil Recovery ◽  
Chemical Equilibrium ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
History Matching ◽  
Geochemical Modeling ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Gravity Segregation

Abstract Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO2 injectivity alteration based on geochemical reactions in carbonate rocks. In this paper, we present a new method for CO2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO2/water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity. Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO2-WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO2-EOR and carbon sequestration projects.

A numerical study of particle migration in porous media during produced water reinjection

2021 ◽  
pp. 1-34
Author(s):  
Tian Xia ◽  
Qihong Feng ◽  
Sen Wang ◽  
Qinglin Shu ◽  
Yigen Zhang ◽  
...  
Keyword(s):  
Particle Size ◽  
Porous Media ◽  
Oil Recovery ◽  
Produced Water ◽  
Numerical Study ◽  
Particle Diameter ◽  
Particle Migration ◽  
Critical Ratio ◽  
Clear Understanding ◽  
The Impact

Abstract The clogging phenomenon often occurs during the reinjection of produced water due to the suspended particles, which will deteriorate the development efficiency. Many experimental and analytical methods have been introduced to solve this problem; however, few numerical approaches have been proposed to investigate the particle migration in the produced water reinjection process. Moreover, it is hard to obtain a clear understanding directly from the particle scale when the injected particles have different sizes. This paper employs a coupled lattice Boltzmann method and discrete element method (LBM-DEM) to study the aforementioned process. The method was validated by reproducing the Drafting-Kissing-Tumbling (DKT) process. Simulations of migration of injected particles with different sizes through porous media were conducted and three clogging scenarios had been identified. We investigated the impact of injected particle size distribution and porous media on particle migration and concluded the results in the polydisperse aspect. From the simulation, we can conclude that mix clogging is the scenario we should try to avoid. Besides, both critical ratio of particle diameter of porous media to median particle diameter of injected particles (D/d50) and critical standard deviation value exist. The particle size range should be as small as possible in economical limits and the D/d50 value should be larger than the critical value. Our results can provide a good guide for the produced water pretreatment, which can improve oil recovery.

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