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 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.

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 767-783 ◽  
Author(s):  
C.. Qiao ◽  
L.. Li ◽  
R.T.. T. Johns ◽  
J.. Xu
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
Mechanistic Model ◽  
Contact Angles ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Physical Parameters ◽  
Minor Effect

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

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>

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.

A Novel Method To Model Low-Salinity-Water Injection in Carbonate Oil Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1154-1166 ◽  
Author(s):  
Emad W. Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad ◽  
Gary Pope
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
History Matching ◽  
Water Injection ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Summary There are few low-salinity-water-injection (LSWI) models proposed for carbonate rocks, mainly because of incomplete understanding of complex chemical interactions of rock/oil/brine. This paper describes a new empirical method to model the LSWI effect on oil recovery from carbonate rocks, on the basis of the history matching and validation of recently published corefloods. In this model, the changes in the oil relative permeability curve and residual oil saturation as a result of the LSWI effect are considered. The water relative permeability parameters are assumed constant, which is a relatively fair assumption on the basis of history matching of coreflood data. The capillary pressure is neglected because we assumed several capillary pressure curves in our simulations in which it had a negligible effect on the history-match results. The proposed model is implemented in the UTCHEM simulator, which is a 3D multiphase flow, transport, and chemical-flooding simulator developed at The University of Texas at Austin (UTCHEM 2000), to match and predict the multiple cycles of low-salinity experiments. The screening criteria for using the proposed LSWI model are addressed in the paper. The developed model gives more insight into the oil-production potential of future waterflood projects with a modified water composition for injection.

Design and Demonstration of New Single-Well Tracer Test for Viscous Chemical Enhanced-Oil-Recovery Fluids

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1075-1085 ◽  
Author(s):  
Robert Fortenberry ◽  
Pearson Suniga ◽  
Mojdeh Delshad ◽  
Bharat Singh ◽  
Hassan A. AlKaaoud ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Pore Space ◽  
Laboratory Data ◽  
Chemical Flooding ◽  
Oil Saturation ◽  
Single Well ◽  
Partitioning Tracers

Summary Single-well-partitioning-tracer tests (SWTTs) are used to measure the saturation of oil or water near a wellbore. If used before and after injection of enhanced-oil-recovery (EOR) fluids, they can evaluate EOR flood performance in a so-called one-spot pilot. Four alkaline/surfactant/polymer (ASP) one-spot pilots were recently completed in Kuwait's Sabriyah-Mauddud (SAMA) reservoir, a thick, heterogeneous carbonate operated by Kuwait Oil Company (KOC). UTCHEM (Delshad et al. 2013), the University of Texas chemical-flooding reservoir simulator, was used to interpret results of two of these one-spot pilots performed in an unconfined zone within the thick SAMA formation. These simulations were used to design a new method for injecting partitioning tracers for one-spot pilots. The recommended practice is to inject the tracers into a relatively uniform confined zone, but, as seen in this work, that is not always possible, so an alternative design was needed to improve the accuracy of the test. The simulations showed that there was a flow-conformance problem when the partitioning tracers were injected into a perforated zone without confinement after the viscous ASP and polymer-drive solutions. The water-conveyed-tracer solutions were being partially diverted outside of the ASP-swept zone where they contacted unswept oil. Because of this problem, the initial interpretation of the performance of the chemicals was pessimistic, overestimating the chemical residual oil saturation (ROS) by up to 12 saturation units. Additional simulations indicated that the oil saturation in the ASP-swept zone could be properly estimated by avoiding the post-ASP waterflood and injecting the post-ASP tracers in a viscous polymer solution rather than in water. An ASP one-spot pilot using the new SWTT design resulted in an estimated ROS of only 0.06 after injection of chemicals (Carlisle et al. 2014). These saturation values were obtained by history matching tracer-production data by use of both traditional continuously-stirred-tank (CSTR) models and compositional, reactive-transport reservoir models. The ability of the simulator to model every phase of the one-spot pilot operation was crucial to the insight of modified SWTT design. The waterflood, first SWTT, ASP flood, and the final SWTT were simulated using a heterogeneous permeability field representative of the Mauddud formation. Laboratory data, field-ASP quality-control information, and injection strategy were all accounted for in these simulations. We describe the models, how they were used, and how the results were used to modify the SWTT design. We further discuss the implications for other SWTTs. The advantage of mechanistic simulation of multiple aspects of a one-spot pilot is an important theme of this study. Because the pore space investigated by the SWTTs can be affected by the previously injected EOR fluids (and vice versa), these interactions should be accounted for. This simulation approach can be used to identify and mitigate design problems during each phase of a challenging one-spot pilot.

Mass Transport and Exchange Inside Tight Matrix-Fracture Systems During CO2 Huff-n-Puff and Flooding Processes

2021 ◽  
Author(s):  
Bing Wei ◽  
Mengying Zhong ◽  
Haoran Tang ◽  
Lele Wang ◽  
Ke Gao ◽  
...  
Keyword(s):  
Mass Transport ◽  
Oil Recovery ◽  
History Matching ◽  
Open Fracture ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Cycle Number ◽  
Matrix Fracture ◽  
Recovery Dynamics

Abstract The potential of CO2 injection in stimulating tight oil recovery after primary production has been extensively demonstrated previously. However, the processes of mass transport and exchange inside dual-permeability matrix-facture system driven by CO2 remain unclear. To improve our understanding and supplement the existing knowledge, three types of matrix-fracture models were designed and employed to mimic CO2 injection processes (huff-n-puff and flooding modes), named fully open fracture (FOF), partially open fracture (POF), and crossed open fracture (COF) models, respectively. CO2 huff-n-puff and flooding experiments were conducted on these three models to observe the dynamics of pressure and oil recovery factor. Core-scale models were built up by history-matching the oil recovery dynamics through modifying the relative permeability curves based on Corey correlations. The mass transport and exchange processes with the proceeding of CO2 injection were delineated. The results showed that either CO2 huff-n-puff or CO2 flooding was capable of extracting the oil from tight matrix substantially but the increase in oil recovery factor became insignificant with the increase in cycle number or injection time. The oil resided in the proximity of injector, fracture and producer were primarily recovered during CO2 flooding. In the FOF and COF models, the matrix oil near the injector and producer was mainly mobilized. As for CO2 huff-n-puff, the oil saturation of the three models was reduced uniformly throughout the cores with cycles. The high sweep efficiency of CO2 largely mobilized the oil near the injector. It can be generally concluded that injecting CO2 by huff-n-puff protocol might be more beneficial than flooding mode for unconventionals. The results of this paper can provide insights into the oil recovery dynamics and mass transport and exchange induced by CO2 injection in tight reservoirs.

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