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IOR 2019 – 20th European Symposium on Improved Oil Recovery
- Conference date: April 8-11, 2019
- Location: Pau, France
- Published: 08 April 2019
61 - 80 of 122 results
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Numerical Study of Polymer Flow in Porous Media using Dynamic Pore Network Modelling
Authors N. Zamani, I. Cecilie Salmo, K. Sorbie and A. SkaugeSummaryPolymer flooding is a mature EOR technology, in which polymer is generally used to modify mobility ratio to improve volumetric sweep efficiency. Some experimental and numerical studies have revealed that beside volumetric sweep efficiency, polymer is also able to increase microscopic sweep efficiency by mobilizing trapped and diverting fluid towards by-passed oil. Polymer solution is a non-Newtonian fluid, meaning that its viscosity may change at different flow conditions; it may show both shear thinning as well as “flow thickening” behaviour when the extensional viscosity increases sharply at higher flow rates. Both experimental and numerical studies confirm that microstructure properties of rock samples such as pore aspect ratio and connectivity play important role on in-situ rheological properties of polymer solution, especially on the onset of extensional viscosity. Onset of extensional viscosity is an important factor for two reasons: (I) its impact on polymer solution injectivity and (II) its role in potential oil mobilization. Therefore, for an efficient polymer flooding design, several parameters of both rock and polymer properties should be considered, and if possible optimised.
Traditional pore network models use an invasion-percolation approach, which causes some limitations to include EOR methods, since this describes a purely drainage process. However, dynamic pore network modelling of imbibition is more relevant for including EOR processes. In this study, we have developed a new dynamic imbibition approach for pore network model (based on Li et al., 2017 ) for polymer flow, for both single and two-phase flow. Rheological properties such as shear-thinning, shear thickening and a complex rheological model, (includes both shear thinning and shear thickening behaviour) are included in the code. We have studied effect of porous media properties on the onset of extensional viscosity and the code has been validated by comparing with Chauveteau's experimental results and results from the Navier-Stokes approach ( Zamani et al., 2015 ). It is shown that by increasing the aspect ratio, onset of extensional viscosity happens at lower injection rate, which is consistent with experimental and numerical studies.
In addition, effect of polymer solution rheology on fluid distribution at different mobility ratios and initial water saturations are studied. The results show that, at adverse mobility ratio, the more viscous polymer makes thicker fingers and sweep more oil in domain and more injecting fluid is diverted into the bonds perpendicular to the main flow. Meanwhile, higher initial water saturation significantly reduces the sweep efficiency at different mobility ratios.
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The Effect of Total Dissolved Solids and Permeability on the EOR Low Salinity Water Flooding
Authors H. Al-Saedi, R. Flori and W. Al-BazzazSummaryLow salinity (LS) water flooding is an eminent enhanced oil recovery technique due to its performance, cost-effectiveness and the interesting results of oil recovery.
To investigate the benefits of LS water in a different range of low permeable sandstone reservoir, different cores were sampled from different depths of the Bartlesville Sandstone Reservoir located in Eastern Kansas. Three pairs of cores were categorized based on their permeabilities. Four different brine salinities (formation water [FW] salinity is 104,550 ppm and others are diluted from FW) were examined for each pair to probe the role of both dissolved solids and permeability on the LS water performance.
The core-flood results show that as the permeability decreases, the injection of LS water into cores not flooded with FW in the secondary stage is increased. The subsequent flooding of the four brines (including LS water) provided a higher oil recovery than injecting LS water alone regardless of the permeability. The oil recovery using only LS water flooding is higher than the combined FW-d2FW-d10FW flooding in all scenarios, and the highest was 8.93% of the OOIP. The oil recovery using only LS water flooding was higher than FW flooding in all scenarios, and the highest was 15.46% of the OOIP.
On the other hand, the contact angle measurements show that the contact angle of the cores flooded with only LS water is lower than the other cores. This study demonstrates the importance of LS water in low permeable sandstone reservoirs.
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Emulsification Mechanisms in Alkali-Surfactant-Polymer (ASP) Flooding Enhanced Oil Recovery
More LessSummaryAlkali-surfactant-polymer flooding (ASP) is one of most attractive chemical EOR techniques in view of incremental recovery upon waterflooding. Emulsification mechanism in ASP flooding is very important but not well understood. Effects of emulsification in ASP flooding is reviewed based on reported field tests as well as laboratory studies, especially on progress and understanding of ASP flooding in China, where the only commercial ASP flooding has been conducted. The main mechanism of ASP flooding can be summarized to the displacement efficiency improvement due to the ultra-low interfacial tension (IFT) between oil and water and the sweep efficiency increase due to mobility control technique by polymer viscosifying and emulsification effect. Emulsification is crucial in ASP flooding since all ASP flooding pilots were seen emulsification with different extent. Oil emulsifying and emulsion profile controlling was regarded as important in ASP flooding mechanisms. Laboratory tests showed that emulsification increase the oil recovery by 5%-6% when emulsified compared with not emulsified. Experience from Daqing oilfield in China reported that contribution of emulsifying ability of ASP system to oil displacement efficiency can be as high as 30%. Factors affecting emulsification included the properties of oil and water, type and concentration of chemical, water cut, external force applied and permeability. Effects of alkali to ASP system and oil emulsification was carefully studied. IFT was an important but not crucial factor to emulsification. Lower IFT at higher alkali concentration promoted easier emulsification, while too low IFT was detrimental to emulsion stability due to the competitive adsorption of in-situ surfactants and added surfactant in oil/water interface. Addition of polymer was beneficial to the stability of emulsion and the effect of associate polymer recent was obvious. ASP field tests in Daqing oilfield verified the emulsify ability of NaOH was almost the same as Na2CO3, which was quite different from laboratory studies. In all development stages of ASP flooding, emulsification was seen. Injection pattern and water cut affected emulsification. Separate injection of alkali and surfactant as one system, while polymer as the other make higher degree of O/W type emulsion. Emulsification in main slug and vice slug showed difference characteristics, which was attributed to the relative content of surfactants in different water cut stage.
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Polymer Flooding Optimization, Minimizing Fouling in Heat Exchangers
Authors O. Vazquez, M. Cooper, M. Al Kalbani, A. Beteta and E. MackaySummaryPolymer flooding is a well-known enhanced oil recovery (EOR) technique, commonly deployed after water flooding as tertiary recovery. Management of the water produced is an important aspect in production operations, particularly in terms of flow assurance. There has been a great deal of attention to impact of water cycle in production facilities, in terms of inorganic mineral scale deposition, hydrate formation and corrosion. However, the interaction of the water produced and the injected EOR chemicals has not been as thoroughly studied, despite the fact of the significant impact on surface production facilities. Fouling in heat-exchangers is not commonly considered in polymer flooding EOR strategies at the front end engineering and design (FEED) stage. The structure of EOR polymers makes them susceptible to multiple factors within a reservoir environment, such as thermal hydrolysis and the presence of divalent ions the produced water. Polymers in the presence of divalent cations precipitate, known as cloud point, where compatibility reduces with temperature. Therefore, fouling in heat exchangers is expected, when polymer breaks through, and as a consequence the rate of heat transfer decreases. Although, the exact mechanism is extremely complex, due to the numerous chemical and physical phenomena, it depends mainly on the nature of the crude oil and the composition of the produced brine, particularly the concentration of divalent ions. In this study, the impact of fouling in the production facilities is described by the Fouling Index (FI), which is the product of divalent ions concentration in the produced water and the produced polymer concentration.
The purpose of this manuscript is to identify optimum polymer flooding strategies in a five-spot pattern heterogeneous synthetic reservoir model, minimizing the level of fouling in the heat exchangers, by minimizing FI. Fouling in heat exchangers prevent the efficient production of hydrocarbons; with the corresponding halt in production and loss of revenue. The optimization results identified the optimum injection polymer concentration and optimum injection water salinity. The results highlighted that reducing the salinity around 50% of the original value, the project net present value (NPV) was optimized, minimizing FI and therefore achieving an optimum oil production. The reduction of salinity can be achieved economically using nano-filtration at the lowest level of rejection, 60%. In conclusion, the results identified optimum polymer flooding strategies, where oil recovery and NPV is maximized, fouling is minimized, aiming for the most efficient continuous oil production.
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Development of Effective Carbonate Steamflood Strategy Using Full-field Simulation Models and Machine Learning Algorithms
Authors S. Ursegov, A. Zakharian, E. Taraskin and A. RunenkovSummarySteamflooding is a widely used thermal method for recovering heavy oil from sandstone reservoirs. In carbonates, the implementation of steamflooding usually demonstrates higher steam-oil ratio and lower oil recovery. The key performance problem is a poor sweep efficiency of steam injection. It is fully confirmed by actual results of steamflooding in the Permian – Carboniferous carbonate reservoir of the Usinsk field located in Northwest European Russia.
The reservoir has the largest heavy oil remaining reserves in carbonates of Russia and Europe. Since the viscosity of its oil is more than 700 mPa*s, in some areas of the reservoir, there is a steam injection at ~300°C and ~10 MPa, which are being used for almost 40 years mostly via vertical wells. However, the current oil recovery numbers of the areas are estimated only between 12 and 15 %. It is assumed that these oil recovery efficiencies could be improved with optimized reservoir management with advanced numerical modeling to evaluate the additional oil production and steam-oil ratio and figure out the best further steamflooding strategy. For many years, an exclusively deterministic approach was used to simulate the reservoir, which significantly limited the possibilities for modifying the steam injection process. That is why, the search for alternative approaches of reservoir modeling, which ensure prompt obtaining realistic forecasting of its development, was relevant. In this work, a novel forecasting technology termed an adaptive approach that combines the full-field geological and hydrodynamic models with the unique machine-learning algorithm based on fuzzy-logic functions was implemented. The obtained results of the adaptive approach application demonstrated the improvement in understanding of the reservoir thermal performance and in making the practical recommendations of cost saving and oil production increase.
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Investigation of Anhydrite Dissolution as a Potential Low Salinity Waterflooding Mechanism in Carbonates
Authors T. Uetani, H. Kaido and H. YonebayashiSummaryMany mechanisms have been proposed for low salinity waterflooding enhanced oil recovery (EOR) in carbonate rocks over the last decade, and they are still in debate. One suggested mechanism is the dissolution of anhydrite (CaSO4) mineral from a rock material, which generates sulfate ions in-situ, and subsequently acts as a wettability modifier chemically. Another suggested mechanism is the increase in permeability due to mineral dissolution. Primary objective of this work was to verify whether dissolution of anhydrite could be the key low salinity waterflooding EOR mechanism.
Spontaneous imbibition tests were conducted using six rock samples from two carbonate oil reservoirs. The first reservoir rock contains anhydrite, while the second reservoir does not contain anhydrite. If anhydrite dissolution is the key mechanism, then the amount of increased oil recovery due to low salinity brine should correlate with the amount of anhydrite dissolved from the rock. Our experimental results, however, did not suggest such a relationship. Hence, anhydrite dissolution was considered unlikely as the key mechanism of low salinity EOR for the crude-oil, brine and rock (COBR) system used in this study.
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Applying the Calibrated Todd and Longstaff's Mixing Parameter Value for Miscible Slug Size WAG Injection on Field Scale
More LessSummaryThis paper presents the application of the calibrated values of the Todd and Longstaff's mixing parameter, ω, for miscible finite-sized slug WAG (FSS WAG) injection on a field scale. This work is an extension of the work of calibrating the mixing parameter value ( Al-Haboobi, 2019 ) where Al-Haboobi showed there is a relationship between the value of ω with specific slug size and WAG ratio. The application on a field scale was through the use of a black oil simulator, Eclipse E100, and was designed to show the reservoir performance obtained using the calibrated values of ω for 1:1 WAG ratio at different slug sizes. Also, to compare the reservoir performance at the calibrated value with a full mixing ω =1 and with Todd and Longstaff's value = ⅔. Todd and Longstaff recommended a value of ⅓ to be applied on a field scale to take into account the effect of heterogeneity. However, the value of ⅔ is used in this comparison, because this comparison was established in the original work of calibrating the mixing parameter value ( Al-Haboobi, 2019 ).
Two case studies were used to test the reservoir performance and the impact of the calibrated value of ω on the reservoir performance, a synthetic quarter five spot model and a semi-synthetic model (the Watt field model). The quarter five-spot model allowed the demonstration of some of the key features of FSS WAG injection in a 3D model without the additional complexity of multiple wells, horizontal producers, faults, and complex permeability and porosity distributions, such as those in the Watt field model.
The paper begins by presenting the models under study, their fluid properties and the grid-refinement study conducted on both models. Then, the paper provides the assumptions of applying the calibrated value of ω on a field scale. Finally, it shows the results and the impact of the calibrated value of ω on the WAG zone and the oil recovery factor.
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The Impact of Calibrating Todd and Longstaff's Mixing Parameter on Optimising Miscible Finite Sized Slug WAG Injection
More LessSummaryThis paper presents the work of optimising the WAG ratio and slug size in miscible finite sized slug WAG (FSSWAG) injection on a field scale, considering the impact of Todd and Longstaff's mixing parameter (ω, also known as TLMIXPAR) value. This work is an extension of Al-Haboobi's (2019 ) work where Al-Haboobi showed there is a relationship between the value of ω with specific slug size and WAG ratio. This relationship was used in the optimisation of slug size and WAG ratio by updating ω (TLMIXPAR) in the Eclipse 100 data deck using a Python code.
In order to identify the impact of the calibrated value of ω on the optimisation of miscible FSS WAG injection, the slug size, WAG ratio, type of fluid injected (so-called WAG pattern injection) and the flow rate were optimised. The optimisation scenario is performed with the assumption that there is an unlimited supply of gas to inject, what if the gas supply was finite (limited)? Therefore, the impact of the calibrated value of ω on the optimisation results has been investigated by adding the assumption that there is a limited amount of gas to inject for the optimisation of WAG ratio, slug size, WAG pattern injection and the amount of flow rate to inject. The results of the previous optimisation scenarios for the calibrated value of ω are compared with the results of the optimisation at a fixed value of ω=1 for both secondary and tertiary recovery. The full details of this work can be found in ( Al-Haboobi, 2019 ).
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Numerical Simulation of Low Salinity Waterflood on Fractured Chalk Outcrop-based Models
Authors N. Andrianov and H.M. NickSummaryWe focus on numerical simulation of low salinity waterflood on outcrop-based models, which are representative of North Sea fractured chalk reservoirs. To this end, we consider a 2D model of an outcrop at Lägerdorf quarry in northwest Germany, which reveals an extensive fracture network together with several major faults, see Koestler and Rekstein (1995). The model is populated with rock and fluid properties, representative for North Sea chalk reservoirs, see Graue and Bognø (1999 ).
We discretize the domain using a Discrete Fracture Matrix (DFM) approach so that the fractures are represented as low-dimensional finite volumes, see Gläser et al. 2017 . Low salinity waterflood is modelled as a two-phase oil-water immiscible displacement with oil being a single component incompressible liquid. The water phase is represented either with two components – high-salinity (HS) and low-salinity (LS) injection water, or with a variable number of chemical elements. In the latter case, the thermodynamic equilibrium for the water phase is achieved by coupling the transport solver to the reaction module PhreeqcRM of Parkhurst and Wissmeier (2015 ). This model was implemented in DuMuX, a free and open-source simulator for flow and transport processes in porous media, see Flemisch et al. 2011 .
We run a sensitivity study on the dependency of recovery rate on water injection rates for various fracture apertures and wettability distribution. The results demonstrate that for certain range of injection rates there is an optimal value in terms of recovery rate vs. number of pore volumes injected.
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Interpretation of Induction Time and Nonstandard Spontaneous Imbibition Trends Utilizing In-situ Measurements – Identification of No-Flow Regions and Wettability Alteration
Authors P.Ø. Andersen, T.L. Føyen, J.S. Chauhan and B. BrattekåsSummaryThis work aims to analyse and explain non-standard imbibition, observed here and frequently in the literature. Previously conducted spontaneous imbibition tests in fully oil-saturated and strongly water-wet Bentheimersandstone core plugs, using OEO (One End Open) and TEOFSI (Two Ends Open Free Spontaneous Imbibition) revealed a significant delay at start of imbibition (induction time) before standard theoretical recovery vs time behaviour was established. The radial corefaces had been sealed with epoxy glue to define no-flow boundaries and yield imbibition corresponding to one dimensional (1D) solutions. However; in-situ imaging revealed that flow occurred in a two-dimensional (2D) manner. Particularly, in-situ imaging showedthat the water saturation at the end of imbibition was much higher in the core center than close to the no-flow boundaries. The tests were simulated numerically to interpret possible causes for the non-standard behaviour. First, the core scale model was parameterizedby matching AFO (All Faces Open) experiments (same experimental conditions, but not applying epoxy) and some of the TEOFSI tests that seemed able to be corrected for induction time. The predicted behaviour of the remaining tests was in agreement in terms ofimbibition rate if an induction time correction was made, however much lower recovery was observed than predicted.
Introducing no-flow regions in the model near the epoxy layers and an initially weakly oil-wet state centrally in the core were both necessary mechanisms to fully interpret the tests.The no-flow regions explained the difference in end recovery, but also impacted the imbibition rate (it was reduced). The initial weakly oil-wet state explained the low, but not zero imbibition rate in the induction period. A wettability alteration towardsstrongly water-wet then explained the resulting behaviour. It was found that this event was more likely triggered than gradual. It was however challenging to determine the triggering event.
This work demonstrates that spontaneous imbibition tests are very sensitive to the flow properties near the no-flow boundaries and can potentially affect the interpretation of end pointsaturations and flow functions. In-situ imaging by PET-CT improved the interpretation of the results by direct implementation of no-flow regions in the model. Accurate spontaneous imbibition behaviour must be achieved in the laboratory before upscaling tothe field.
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Optimization of Gas-condensate Reservoir EOR Technology under Geological Uncertainties
Authors O. Burachok and O. KondratSummaryDevelopment of gas-condensate reservoirs is a complicated problem by itself. The classic way to enhance hydrocarbon recovery from fields with high condensate yield is to implement hydrocarbon or nonhydrocarbon gas injection to support reservoir pressure high enough to be close to dewpoint pressure. Application of chemical EOR methods was not really suggested in the industry for gas-condensate fields. Commonly, identifying the optimum technology for the field is based on a single geomodel realization concept that enables unbiased comparison of suggested technologies. Unfortunately, when we are considering selection of the technology for a pilot field application, we are still highly uncertain about property distribution and even fluid properties and their true interaction with injected chemicals.
The problem becomes even more complicated when we also have to optimize the implementation of the technologies based on technical or economic efficiency. The current paper proposes the workflow that addresses the problem described above.
The classic approach for enhancement of condensate recovery is implementation of gas recycling using hydrocarbon or nonhydrocarbon gases. This proves to be efficient method in cases when reservoir pressure is maintained close to dewpoint, preventing in-situ condensation of liquid fractions. The problem of current study is a synthetic deep gas-condensate reservoir that was developed under depletion, resulting in significant decrease of reservoir pressure way beyond dewpoint with formation of the liquid phase, which is only mobile in the vicinity of the wells, where critical saturations were achieved. Being uncertain about geological description of the reservoir, facies distribution, porosity, permeability, and SCAL data, we want to identify the most economically feasible chemical EOR technology and optimize its parameters under uncertainties. Using a numerical compositional simulator with a synthetic reservoir model, we performed optimization of a field development project's net present value (NPV) for different chemical EOR methods – surfactant (S), alkaline (A), polymer (P), AS, SP, and ASP for the duration of injection (slug volume) under geological uncertainties within different static reservoir property realizations, fault transmissibilities, aquifer strength, and relative permeability endpoints. Optimization was done using a simplex algorithm combined with risk assertion to account for geological uncertainties.
Results indicate repeatability and applicability of the proposed approach on real full-field gas-condensate models.
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Analytical and Numerical Solutions of Chemical Flooding in a Layered Reservoir with a Focus on Low Salinity Water Flooding
Authors H. Al-Ibadi, K. Stephen and E. MackaySummaryChemical flooding has been implemented and studied intensively as an EOR method. One such process, Low Salinity WaterFlooding (LSWF) has become increasingly applied. Simulations can be performed for these processes to predict behaviour and make field management decisions. These are costly and incur numerical errors. Analytical solutions to flow behaviour have been developed previously for waterflooding in reservoirs that consist of non-communicating layers. We extend that analysis here for chemical flooding, and in particular for LSWF. We also extend the analysis that we developed previously to include dispersion effects. We then compare the analytical predictions to the more realistic case of flow across communicating layers to assess crossflow effects. We derive a mathematical form of fractional flow theory for a set of non-communicating layers that can be used to predict fluid flow and solute transport including the location of waterfronts. This model corrects for the effects of numerical and physical dispersion. We examine the validity of this analytical model by comparing it to simulations of fluid flow behaviour in non-communicating layers first and then in communicating layers. We use dimensionless numbers that can be used to deduce the inter-layer relationships of the various fronts that form as a function of viscous crossflow. We examined models with different degrees of heterogeneity under various mobility ratios.
The analytical method worked very well compared to numerical simulations in the absence of cross-flow. Our results show that for virtually homogenous reservoirs, the crossflow has negligible effect on oil recovery. For moderately heterogeneous reservoirs, the crossflow has a negative effect reducing the recovery factor. Cross flow resulted in varying effects ranging from a reduced ultimate recovery of 2% or increased it by 9%, relative to the original oil in place. The former occurred for models with a mobility ratio at the leading formation waterfront that was less than one combined with low heterogeneity while the latter occurred for highly heterogeneous cases.
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A Modeling Study for Foam Generation for EOR Applications in Naturally Fractured Reservoirs Using Disperse Surfactant in the Gas Stream
Authors J.D. Valencia, J.M. Mejía, A. Ocampo and H. SolanoSummaryThe preferential flow channels in oil reservoirs affect the performance of oil recovery processes, reducing the sweep efficiency and affecting the expected recovery factor. Preferential flow channels are generated by viscous fingering, gravitational segregation or porous media heterogeneity like natural fractures. In the Colombian foothills fields where the gas injection is the main method of recovery, the gravitational segregation and the presence of natural fractures strongly reduce the sweep efficiency. For these fields, foam generation is an alternative with high potential to increase sweep efficiency in gas displacement processes. Different foaming methodologies have been evaluated at laboratory core scale and field pilots with good incremental production, but with high operational expenses associated with high surfactant retention and lack of water injection facilities. Dispersed surfactant injection in a gas stream is a new proven method for foam generation. Different core flooding results and field pilots have shown that disperse injection increase cumulative oil production. However, there is a high level of uncertainty due to a few experimental and field information. For compensating the high uncertainty of the method, a mechanistic model was previously developed and validated with information from homogeneous cores. Nevertheless, it is necessary to extend the scope of the model to evaluate the effect of blocking foams in naturally fractured reservoirs, in this work we scale the previously built foam models to evaluate the disperse surfactant injection in Naturally Fractured Reservoirs through thin, high permeability, and horizontal layers to represent fractured systems and reproduce laboratory and field pilot results.
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Single Well Modeling and Field Validation of Heavy-oil Well Stimulations Using Nanofluids
Authors J. Mejia, R. Zabala and J. ValenciaSummaryEngineered nanofluids were designed to reduce oil viscosity and to restore wettability in heavy oil formations ( Zabala et al. 2016 ). Incremental production rates, between 50% and 150%, were registered after injecting the nanofluids in 4 wells in two heavy oil fields of the Llanos Basin in Colombia ( Zabala et al. 2016 ). A rigorous mathematical model of the interaction of nanoparticles in heavy-oil systems was developed by Mozo et al. (2018 ). The model accounts for transport and retention of nanoparticles, wettability alteration and oil viscosity reduction. The model was developed for 1D-linear flow in order to calibrate the model parameters with core-flooding experiments. In this work, we extended the model to radial models in 3D in order to simulate the injection, soaking and production stages of a nanofluid injection in a well. The equations were discretized using the finite volume method. The non-linear equations were sorved using the Newton-Raphson method. Two wells of the pilot study were simulated, showing a good agreement with field measurements of oil production. Since the model accounts for the underlying physical and chemical processes, the deployment of a well stimulation can simulated and evaluated using the developed tool. We simulated different nanofluids injection scenarios at reservoir scale in order to assess the impact of unknown model parameters as well as main operating conditions on the incremental oil production. The sensitivity analysis results provides important information for designing experimental and field protocols for model tuning and validation, as well for designing effective surveillance activities related to the pilot / field applications. References
Mozo I., Mejía J. M., Cortés F., Zabala R. (2018). A robust mathematical model for heavy-oil well stimulations using nanofluids: modelling, simulation and validation at lab and reservoir scales. 16th European Conference on the Mathematics of Oil Recovery- EAGE. 3–6 September 2018 . Barcelona, Spain. Zabala R., Franco C. A., & Cortés F. B. (2016). Application of Nanofluids for Improving Oil Mobility in Heavy Oil and Extra-Heavy Oil: A Field Test. Society of Petroleum Engineers. SPE-179677-MS.
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A New Qualitative and Quantitative Analytics Approach on Waterflood Operations Data for Improving Oil Recovery
Authors A. Venkatraman, A. Malkov, A. Yadav, D. Davudov, K. Awemo, T. Hag and X. ChenSummaryWater flooding is an established method of secondary recovery to increase oil production. While previous research has focused on designing waterflood operations, there are no tools to evaluate the efficacy of those designs and optimize it frequently based on data available during the course of water flooding operations. In this research, we present a novel approach of using data mining techniques to increase oil recovery using operations data from a field undergoing water flooding. The results presented in this research can be adapted to any field to optimize recovery at frequent intervals, where injection and production data is continuously available.
Operations data from a current water flooding field is used to improve water injection strategy by using a combination of qualitative (cross correlation analysis) and quantitative analysis (capacitance resistance model). Field data obtained from each injector and the surrounding producers are used for cross correlation analysis that enable identifying thief zones. The qualitative insights obtained from the cross-correlation analysis are used to improve the capacitance resistance model for the field. The improved capacitance resistance model is used to obtain redistribution of water among injectors with the purpose of increasing oil recovery. Reservoir simulation prediction of oil recovery on the two cases (the previous benchmark case and the new optimized injection strategy obtained using data mining techniques) is presented. It can be seen that the redistribution of water obtained using this novel approach improves oil estimates in the range of 5–10%.
A field case of using data mining techniques of cross correlation analysis and capacitance resistance modeling is presented as a means to improve reservoir characterization using operations data. The insights obtained by using a combination of these two methods are used to redistribute water injection in a producing field. This new approach can be used to optimize water injection at frequent intervals based on the operations data obtained from the field. Operational challenges in implementing redistribution of water injection rates frequently are highlighted for the sake of other operators implementing such an approach.
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An Adaptive Newton's Method for Implicit Dynamic Local Grid Refinement for Simulation of IOR/EOR Processes
Authors H Groot, H Cui, J Rommelse and D VanBatenburgSummaryDynamic Local Grid Refinement (DLGR) is a well-known computational method to improve the performance of reservoir simulations by dynamically adapting the grid resolution to local physical phenomena at each location in time. This enables reservoir simulators to achieve similar accuracy with only a fraction of the number of grid cells that it would otherwise utilize. This is particularly useful for IOR/EOR processes due to the small scale and complexity of the physical and chemical processes involved.
A challenge in using DLGR is the adaptation of the local grid resolution in advance of dynamic changes in physical phenomena, such as moving thermal or oil displacement fronts. Failure to intercept such changes up front by a locally high resolution grid will lead to loss of numerical accuracy. A Repeat Time Step (RTS) method that iteratively repeats time steps to implicitly evaluate the grid adaptation criteria at the next time node was previously proposed. However, the results in this paper show that using the RTS method for DLGR leads on average to considerably higher computational time spent in the linear solver. As a result, it was found that it is more efficient in most cases to tighten the tolerances for the grid adaptation criteria in order to create a buffer zone of fine grid cells in regions that require high grid resolution instead of using the RTS method.
This report proposes an iDLGR-ANM method in which an Adaptive Newton's Method (ANM) is used to further reduce computational overhead spent in repeat time steps performed by DLGR. The ANM leads to reduced simulation times by only considering unconverged and adjacent grid cells in each NR iteration. Furthermore, the added benefit of ANM to the RTS method is that ANM can immediately be restricted to refined grid cells and adjacent cells from the first NR iteration in the repeat time steps rather than solving the full system of linearized equations. In order to compare the performance of the RTS method with and without the ANM, eight examples are considered involving various IOR/EOR applications and numerical schemes. Results show that iDLGR-ANM is nearly as fast in terms of CPU time spent in the linear solver as DLGR without using the RTS method. Moreover, if a post-Newton material balance smoothing technique is applied, iDLGR-ANM results in production forecasts with the same accuracy as DLGR when the RTS method is used without ANM, with differences within machine accuracy.
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Velocity Enhancement Models for Polymer Flooding in Reservoir Simulation
Authors J. Romate and E. GuarnerioSummaryPolymer flooding is a well-known technique used in EOR. In order to accurately predict oil recovery, a velocity enhancement effect for the polymer molecules, also known as hydrodynamic acceleration, has to be included in the governing equations. The traditional model of a constant velocity enhancement factor, widely used in commercial simulators, leads to an ill-posed problem. As a consequence, simulations may produce unphysical solutions, showing an unlimited accumulation of polymer at the propagation front. Therefore, alternative models have been derived in order to formulate a well-posed problem. In this paper, these models are re-examined. Using mathematical theory of hyperbolic laws, an analytical solution is computed for the velocity enhancement model proposed by Bartelds et al. (G.A. Bartelds, J. Bruining, and J. Molenaar. The modeling of velocity enhancement in polymer flooding. Transport in Porous Media, 26(1):75–88, 1997). A property of this solution is that the polymer concentration decreases as polymer flows through the porous medium and no accumulation effect occurs. The polymer front travels faster than the case where no enhancement model is used, but a constraint on a parameter, needed to ensure well-posedness of the problem, limits the magnitude of the polymer acceleration. Hence, Hilden et al. (S.T. Hilden, H.M. Nilsen, and X. Raynaud. Study of the well-posedness of models for the inaccessible pore volume in polymer flooding. Transport in Porous Media, 114(1):65–86, 2016) proposed an extended model in order to overcome this constraint. However, it is shown in this paper that the model of Hilden results in a loss of hyperbolicity of the system of equations and may lead again to an unphysical accumulation of polymer at the propagation front. As many simulators still employ the ill-posed traditional model because of the uncertainty of the outcomes of alternative approaches, this analysis will hopefully help to understand the consequences of velocity enhancement modeling on the analytical and numerical solutions of polymer flooding.
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EOR Back Produced Water Treatment: Media Selection to Improve Filtration Efficiency
Authors N. Lesage, H. Foraison, J. Lafourcade, M. Jouanolou, G. Munduru, C. Sagne, P. Pedenaud and P. CordelierSummaryPolymer flooding is one of the most advanced enhanced oil recovery techniques to improve production. It is a cost-effective method due to the properties of polymers, mainly its capacity to develop suitable viscosities when diluted, leading to an improved hydrocarbon's extraction. The technique consists in injecting Hydrolyzed Polyacrylamide polymer (HPAM), mixed with water, in the reservoir to reach a target viscosity, in order to guarantee oil extraction, while reducing a bit the water cut. However, back produced water viscosity is quite high and leads to poor water treatment efficiency. Several water treatment technologies for oil removal have been developed for this purpose using gravity separation, gas floatation, chemical treatment and filtration. The media filtration is one of the most attractive technology because it has low operating costs and can handle high flux rates; it can help switch from water flooding to polymer flooding by retrofitting existing water treatment facilities, and so minimize CAPEX. This technology is very efficient to treat the produced water (PW) and can reach a very low oil concentration (<5mg/L). Nevertheless the filtration efficiency is function of the PW quality as well as media selected for the filtration.
The aim of this study was to compare the efficiency of several media for the treatment of produced water and back produced viscosified water. The impact of the polymer concentration (500 mg/L) on the retention efficiency was demonstrated in batch and continuous modes on synthetic produced water (50 mgOil/L, 10 mg/L of calibrated particles, 100 mg/L corrosion inhibitor). Indeed, the high viscosity of the PW mostly increases the fouling velocities. First tests aimed at screening the oil retention in batch mode for 6 different kinds of media (3 nutshell, sand, and a polymeric media). The 3 best media were then tested in continuous mode (flow 15–25 m/h) with automatic cleaning phases. This phase allowed assessing the regeneration efficiency and the ageing of the media. Results of the tests concluded on the impact of the water quality on the retention efficiency and design parameter for the media filtration of back produced viscosified water. Thanks to this study, several selection criteria of media were highlighted to adapt this technology for each field case.
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Evaluation of Empirical Models for Viscous Fingering in Miscible Displacement
Authors I. Tai and A. MuggeridgeSummaryThe performance of miscible gas injection projects can be significantly affected by viscous fingering. This is further complicated by the presence of heterogeneities, as depending on the scale of the heterogeneity, there can be a diffusive, advective or channelling effect. To assess the economic feasibility of a miscible gas injection project, reservoir simulations are needed but very fine grids are required for the fingers to be modelled explicitly. This requires a large amount of computational power and time. To get around this issue, many empirical models have been proposed which model the average behaviour of the viscous fingers, allowing predictions of performance, thus reducing grid size and computational time.
Many previous studies have investigated the ability of empirical models to represent fingering in line drives but none have considered flow in a quarter five spot pattern. In this study, a two phase, three component higher-order simulator is used to simulate miscible injection in square line drive and quarter five spot models, with and without heterogeneities. The results of the detailed fingering simulations were compared to the Todd & Longstaff and Fayers empirical models. To account for the effect of heterogeneities, the mixing parameter, w, in the Todd & Longstaff was adjusted using Koval's heterogeneity factor, H_k. The growth rate of the fingers, α, and the final fraction of the cross section occupied by the fingers, a+b, were adjusted in the Fayers model to account for heterogeneities and bypassed oil. The empirical models were implemented in a commercial immiscible reservoir simulator, Eclipse-100 using pseudo relative permeabilities.
The detailed simulations indicate that the growth rate of the fingers varies non-linearly with mean concentration in radial flows and this is not captured by either of the empirical models. A modification of the Fayers model is proposed to capture this. For both heterogeneous line drive and quarter five spot models, the Todd & Longstaff model consistently overestimates recovery after solvent breakthrough as it cannot account for bypassed oil. The Fayers model underestimates recovery whereas the modified Fayers model tends to overestimate the breakthrough time, but after this point, it can accurately reproduce the effluent profile from simulations. However, this requires production data or detailed fingering simulation data to calibrate b, the constant which defines bypassed oil, as this depends on the heterogeneity, the mobility ratio and the time scale of interest
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The Development of a Low Shear Valve Suitable for Polymer Flooding
Authors T. Husveg, M. Stokka, S. Jouenne and R. HusvegSummaryHydrolyzed polyacrylamides are used as mobility control agents to improve the macroscopic sweep efficiency of oil reservoirs. In order to maximize their viscosifying power, very high molecular weight polymers are preferred, which in turn make them very sensitive to shear degradation.
Shear degradation originates from chain stretching and breaking when the solution is subjected to a sudden acceleration. Such extension dominated flow fields are encountered at different locations of surface facilities (mainly in pumps, pipes and valves) and at the wellbore interface. Although CAPEX intensive, the use of one injection pump and line per injector well is a way to control and to minimize polymer degradation. For mature field developments or large fields with long injection lines, it is generally necessary to install a control valve on the wellhead of each well to regulate the injection pressure and flow rate.
In classical chokes used for water flooding, the fluid accelerates strongly in order to create the turbulence required for pressure reduction, which in turn leads to a high degradation of polymer chains. Fundamental development work is presented, where polymer degradation is studied in flow through diffusers and expanders of various geometrical shapes, as well as through straight pipes and pipe coils of various diameters and lengths. Empirical correlations between geometries and polymer degradation are established. In particular, for a given flow capacity, it is found that the optimal geometry of a tube-based throttling device, is a compromise between length, diameter and number of tubes in parallel. Results demonstrate that the creation of pressure drop through viscous pipe friction is very ineffective with tubes of constant diameter, most likely due to the drag reducing effect of polymer flow. In addition, the arrangement of very long, straight or coiled tubes in parallel is impractical and bulky.
A novel valve technology solves these challenges: Firstly, through the unique use of carefully designed contractions evenly spaced in the flow channels, the drag reducing effect is overruled. Secondly, the arrangement of multiple flow channels of certain diameters and lengths, and with optimally designed reducer and expansion zones, resolves itself by using a stack of machined spiral discs. The latter also enables an easy and reliable technical solution for flow and pressure regulation. The efficiency of the new valve technology is demonstrated through small and large-scale prototype tests. Degradation is less than 10% at 40 bar pressure drop compared to 80% for a standard valve.
Hydrolyzed polyacrylamides are used as mobility control agents to improve the macroscopic sweep efficiency of oil reservoirs. In order to maximize their viscosifying power, very high molecular weight polymers are preferred, which in turn make them very sensitive to shear degradation. Shear degradation originates from chain stretching and breaking when the solution is subjected to a sudden acceleration. Such extension dominated flow fields are encountered at different locations of surface facilities (mainly in pumps, pipes and valves) and at the wellbore interface. Although CAPEX intensive, the use of one injection pump and line per injector well is a way to control and to minimize polymer degradation. For mature field developments or large fields with long injection lines, it is generally necessary to install a control valve on the wellhead of each well to regulate the injection pressure and flow rate.
In classical chokes used for water flooding, the fluid accelerates strongly in order to create the turbulence required for pressure reduction, which in turn leads to a high degradation of polymer chains. Fundamental development work is presented, where polymer degradation is studied in flow through reducers and expanders of various geometrical shapes, as well as through straight pipes and pipe coils of various diameters and lengths. Empirical correlations between geometries and polymer degradation are established. In particular, for a given flow capacity, it is found that the optimal geometry of a pipe-based throttling device, is a compromise between length, diameter and number of pipes in parallel. Generally, the work also demonstrates that the creation of pressure drop through viscous pipe friction is very ineffective with regular tubes, most likely due to the drag reducing effect of polymer flow. In addition, the arrangement of very long, straight or coiled pipes in parallel is impractical and bulky.
This paper presents the development of a novel valve technology that solves these challenges. Firstly, through the unique use of spiralling flow channels with optimally designed reducer and expansion zones, machined on the surface of discs, shear forces and thereby polymer degradation is controlled. Secondly, the arrangement of numerous such disc forming a disc-stack, any target capacity can be met efficiently. Thirdly, the disc-stack concept enables an easy and reliable plug-based solution for flow regulation and control. The performance of the new valve technology is demonstrated through small and large-scale prototype tests. At very shear sensitive test conditions, it is demonstrated that polymer degradation of the new valve is less than 10 % at 40–45 bar pressure drop, compared to 60–80 % for a standard valve.
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