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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
21 - 40 of 122 results
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A Mechanistic Model for the Fines-migration During the Modified-salinity Waterflooding in Carbonate Reservoirs
Authors M. Bonto, A.A. Eftekhari and H. NickSummaryThe fines migration is one of the most reported mechanisms for the improved oil recovery during low salinity waterflooding in sandstone reservoirs. However, the release of particles and its effect on the recovery of oil from carbonates has received less attention and in this work, we emphasize its role. When injecting a brine incompatible with the formation water, different phases can precipitate which can also lead to more calcite dissolution, releasing some particles from the surface. These particles, together with the detachment of organic layers from the rock surface or the migration of clay minerals present in the formation, can be retained blocking some pore throats and diverting the flow of water to different zones, increasing the sweep efficiency. In the present paper, we first study the mechanical equilibrium of a particle by considering DLVO, drag, lift and gravitational forces, validating the fines migration inferred experimentally from the pressure drop increase for a set of coreflooding experiments. We show that particle detachment occurs also in carbonates when the salinity drops below a certain value. Then, we model the fines migration based on the concept of the so-called critical retention function. Our approach is different from the previous reported models, since we calculate this function from the balance of forces, and not taking it as a constant deduced from pressure drop measurements. Using a constant critical retention function would imply that the electrostatic forces do not change along the core/reservoir, which is definitely not the case for chalk reservoirs, where the calcite minerals are highly reactive. To account for the changes in the electrostatic repulsive forces and therefore in the critical retention function, we couple a CD-MUSIC surface complexation model to our model for fines release. Therefore, at each core position we are able to calculate the critical retention function by considering variables like the ionic strength, pH, pCO2, all of them affecting the electrostatic forces. The main novelty of this work is the coupling of our optimized surface complexation model with the fluid flow, which allows us to better estimate the electrostatic forces, and consequently the critical retention function that will eventually govern the amount of particle released or reattached. With this model, we are able to predict the critical salinity at which fines migration occurs, the transport and capture of the particles, their impact on the effective permeability of water, and the pressure drop profile during low salinity waterflooding.
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Experimental Investigation of Three-Phase Relative Permeability under Simultaneous Water and Gas (SWAG) Injection
Authors L. Moghadasi, M. Bartosek, D. Renna, G. Maddinelli and S. ScagliottiSummaryVarieties of enhanced oil recovery (EOR) processes involve simultaneous flow of two or three immiscible fluids (i.e., water, oil, and gas) in reservoirs. Proper quantification of multi-phase flow processes has considerable economic and scientific importance in management and development of oil- and gas-bearing geologic formations. Relative permeabilities are key rock-fluid properties required for continuous-scale modeling of multiphase flow dynamics in porous and fractured media. A reliable characterization of these quantities, including uncertainty quantification, enables reservoir engineers to assess reservoir performance, forecast ultimate oil recovery, and investigate the efficiency of enhanced oil recovery techniques.
In this work, we report the results of a suite of laboratory-scale experimental investigations of multi-phase (water/oil/gas) relative permeabilities on reservoir core sample. Two (water/oil) - and three-phase (water/oil/gas) relative permeability data are obtained at high temperature of the reservoir by way of a Steady-State (SS) technique. Our laboratory methodology allows improved relative permeability acquisition through a joint use of traditional flow-through investigations and direct X-Ray measurement of the core local saturation distribution. The latter renders detailed distributions of (section-averaged) fluid phases along the core, which can then be employed for the characterization of relative permeabilities. The three-phase Steady-State relative permeability experiments have been conducted by resorting to a dual energy X-Ray methodology. The experimental setup also includes a closed loop system to validate and support saturation measurements/estimates. The SS three-phase experiments are performed by following diverse saturation paths including CDI, DDI, IID and some cycle injection of WAG, where, C, D and I denote as Constant, Increasing and Decreasing (i.e., CDI means Constant water, Decreasing oil and Increasing Gas). Several different flow rate ratios have been selected to cover the saturation ternary diagram extension as completely as possible.
The use of in-situ X-Ray scanning technology enables us to accurately measure depth-averaged fluid displacement during the core-flooding test. We observe in most of the tests, three-phase water relative permeabilities display an approximately linear dependence on its saturation when the latter is subject to a logarithmic transformation. The three-phase oil and gas relative permeabilities, when plotted versus their saturations are scattered by apparently quasi-linear trends, compared to the behavior of water relative permeabilities.
We provide the experimental data set to demonstrate the possible three-phase region and eventually investigate the hysteretic effects on three-phase relative permeabilities. As only a limited quantity of three-phase data are available, this study stands as a reliable reference for further model development and testing.
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Analysis of 3-phase Behavior in WAG Injections for Various Wettabilities
Authors M. Bourgeois, T. Joubert and V.E. DominguezSummaryWAG increments are known to be quite variable, both in the field and in the simulations, and are often analysed by splitting the WAG applications between miscible and immiscible cases.
The authors are quite convinced that the more complex theory combining wettability and interfacial tensions, predicting the wetting order at pore scale, is relevant at core scale, and field scale, and that it could explain some surprisingly good results of immiscible WAG in oil-wet reservoirs, and some disappointing results of miscible WAG in water-wet conditions.
In coherence with this existing theory, we have adapted our wetting model, and extended the Larsen-Skauge model to allow water trapping as well as gas trapping. It allows to reproduce quite well the serious water injectivity limitations for WAG in rather water-wet reservoirs, as well as the absence of this issue in oil-wet operations. We also believe that the 3-phase relative permeability corrections which are applied to the 2-phase inputs need to be consistent with that pore occupancy scheme, and have explained notionally how the parameters should vary with wettability.
Naturally, further work is needed to consolidate these findings, but some suggestions are already made to estimate the new parameters to use with extended 3-phase hysteresis model.
Various representations on ternary diagrams and injectivity plots are proposed, and the link to wettability is discussed.
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Modelling the Transition between Immiscible and Miscible WAG
Authors A. Skauge, K.S. Sorbie and M.I.J. Van DijkeSummaryCurrent WAG modelling is either handling three-phase relative permeabilities with hysteresis and phase trapping, but cannot simultaneously include compositional effects. Whereas, conventional, compositional, WAG models lack the correct multi-phase flow functions (3 phase relative permeabilities, 3PRP). Our objective in this paper is to lay out a programme of research which will close the gap between immiscible WAG and miscible WAG by construction a physics based WAG model that includes best choice of fluid flow functions, saturation dependencies, phase trapping, transition to miscibility, and compositional effects.
We first lay out a mechanistic phase diagram of the 2 major components of any WAG flood immiscible or miscible (more generally near-miscible) , i.e (i) relative permeability effects – flow functiosn and 3PRP and (ii) compositional effects as the gas and oil approach miscibility. At present there is no physically consistent theory which carries over ALL of the various physical effects from the purely immiscible WAG case (with no, or very weak compositional effects) to the near miscible case. As just one example of incorrect physics, the 3 phase wetting order can change as the 3 IFTs change on approach to miscibility; we might think of this change as IFT to gas/oil σgo change towards 0 , but in real systems, the IFT usually decreases and then increases again (as light oil components are stripped out). This wetting change should change the saturation dependencies of the 3PRP functions, but we invariably keep the original form of these functions (e.g.as Stone 1 or 2, which strictly only apply for strongly water-wet systems).
A full agenda laying out all of the required parts of the physics is laid out in this paper and, where the physics is already known, it is briefly explained, and where not some conjectures are made or the challenges are clarified. The authors hope this paper will stimulate both discussion of the physics of WAG processes and more technical research to address the challenges.
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Mesh Adaptivity and Parallel Computing for 3D Simulation of Immiscible Viscous Fingering
Authors A. Kampitsis, P. Salinas, C. Pain, A. Muggeridge and M. JacksonSummaryWe present the recently developed Double Control Volume Finite Element Method (DCVFEM) in combination with dynamic mesh adaptivity in parallel computing to simulate immiscible viscous fingering in two- and three-dimensions.
Immiscible viscous fingering may occur during the waterflooding of oil reservoirs, resulting in early breakthrough and poor areal sweep. Similarly to miscible fingering it is triggered by small-scale permeability heterogeneity while it is controlled by the mobility ratio of the fluid and the level of transverse dispersion / capillary pressure. Up to this day, most viscous fingering studies have focussed on the miscible problem since immiscible fingering is significantly more challenging. It requires numerical simulations capable to capture the interaction of the shock front with the capillary pressure, which is a saturation dependent dispersion term. That leads to models with very fine mesh in order to minimise numerical diffusion, resulting in computationally intensive simulations.
In this study, we apply the dynamic mesh adaptive DCVFEM in parallel computing to simulate immiscible viscous fingering with capillary pressure. Parallelisation is achieved by using the MPI libraries. Dynamic mesh adaptivity is achieved by mapping of data between meshes. The governing multiphase flow equations are discretised using double control volumes on tetrahedral finite elements. The discontinuous representation for pressure and velocity allows the use of small control volumes, yielding higher resolution of the saturation field.
We demonstrate convergence of fingers using our parallel numerical method in 2d and 3d, on fixed and adaptive meshes, quantifying the speed-up due to parallelisation and mesh adaptivity and the achieved accuracy. Dynamic mesh adaptivity allows resolution to be automatically employed where it is required to resolve the fingers with lower resolution elsewhere, enabling capture of complex non-linearity such as tip-splitting. We achieve convergence with less than 10k elements, approximately 5 times fewer elements than are needed for the converged fixed mesh solution, consequently the computational cost is also significantly reduced.
Initial growth rates as a function of wavenumber, viscosity ratio, relative permeability and capillary pressure are compared with the literature. We demonstrate that the structure of the mesh plays a key role in simulation of fingering as it can itself trigger the instability, control the dominant wavelength of the fingers and their growth rate. We show that it is important to characterise the amount of transverse to longitudinal numerical diffusion in a general unstructured mesh in order to ensure that the correct fingering pattern is simulated.
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Injection Test as Milestone for the Applicaton of Polymer Flooding in the German North Sea
Authors C. Burmester, F. Leicht, D. Bols and T. DoseSummaryWith respect to maximising recovery and optimising a field's value, Chemical Enhanced Oil Recovery (CEOR) especially with polymers is frequently an option. This method was identified as a promising method to enhance production from Germany's largest oil field Mittelplate. The field presents challenging operational conditions with respect to surface, subsurface, and environmental constraints. This paper describes the upscaling of lab results to field scale as well as results from a conducted injection field test.
A stepwise scale up from lab to field was performed. On the lab scale, the selection process for this field was presented (EAGE Annual 2018).
Because the subsurface injectivity for polymer solutions of the anticipated target reservoir was unknown, an injection test was planned. Due to the unknown injection parameters for the test, a mixing unit was constructed based on the results from the pilot plant tests. The main criteria for the design were operational safety considerations and high flexibility with respect to flow rates and mixing energy while maintaining a high quality of the mixed polymer solution with produced water.
At the pilot plant scale, continuous mixing tests with equipment from different suppliers and different setups were carried out for rates up to 600 l/h. A yard test of the mixing unit using field injection water generated valuable lessons, which completed the onshore evaluation for offshore field application.
In the 3rd quarter 2017, an injection test on Mittelplate Island was carried out. The test was conducted with produced water (190 g/1) without any special treatments sourced from the injection water system. The solution quality was very good and injectivity was above expectations. No plugging behaviour and no significant shear degradation of the injected solution was observed which confirms lab results regarding an excellent shear stability of the mixed polymer solutions. The injection index of the injector was well preserved.
Overall the test proved the applicability of the selected chemical system with high salinity injection water on Mittelplate.
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Development of Conformance Gel for Diadema Oil Field using Powder and Emulsion Polymers and their Impact on Equipment and Economics
Authors G. Dupuis, S. Bataille, J. Monzon, N. Gaillard, G. Fondevila Sancet, M. Villambrosa, M.D. Goldman and M. AlvarezSummaryDiadema Oil Field is located in the San Jorge Gulf Basin in Southern Argentina. The field is operated by CAPSA, an Argentinean oil producer company; it has around 500 producer and 300 injector wells (well spacing is around 250 m). The company has been developing water flooding during more than 25 years (today this technique represents +65% of oil production), polymer flooding during more than 10 years and (+15% of oil production); produces about 1,850 m3/d of oil and 45,000 m3/d of gross production (96% water cut) with 43,000 m3/d of water injection.
The main reservoir under secondary recovery is characterized by high permeability (500 md average), high heterogeneity (10 to 5000 md), high porosity (30%), very stratified sand-stone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin) and 20 °API oil (100 cp at reservoir conditions, 50 °C). Due to such reservoir conditions, injectors and producers are subject to channeling problems.
Polymer gels have been extensively used to tackle such conformance issues. The criteria of success do not only depend on the quality of the technical solution but also on economics. Generally, gels are formulated using polymers under powder form requiring the mobilization of a dissolution unit, a maturation tank and one to several dilution tanks. On the opposite the utilization of polymers under reverse emulsion form only requires the use of a single skid including a static mixer for the inversion of the emulsion and one or two static mixers for polymer dilution and homogenization with the crosslinker, reducing both the footprint of the equipment (important for offshore) and the cost of the treatment.
Two gel formulations using Chromium (III) acetate as crosslinker and partially hydrolyzed polyacrylamide either under its powder or its reverse emulsion version were developed to fit field conditions targeting a gel D category according to Sydansk classification and a gel time below 36 hours. A cost analysis comparison of both formulations was performed to select the more efficient solutions.
Gels C to D were achieved for both formulations, 15 hours gel time and good stability over 3 months. The economical evaluation showed that the cost saving associated to the use of a single skid did not compensate the extra price of the reverse emulsion compared to the powder. The formulation using HPAM as a powder was selected and 20+ injection wells were treated without facing any operational issue.
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First Use of Ultra-Deep Resistivity 2D Deep Azimuthal Images to Identify Reservoir Sweep in a Mature Waterflood of Al-Shaheen Field
Authors S. Finlay, D. Omeragic, M. Thiel, N. Farnoosh, J. Denichou and M. ViandanteSummaryThe Al Shaheen field has been on production for 25 years and is developed using waterflood and ERD wells, some of which are openhole. Production logging Tools are occasionally required to assess waterflood performance, and the implementation of appropriate mitigation steps. Wellbore architecture and offshore facility limitations make conventional production logging challenging. Therefore to identify swept zones or non-conformances an ERD producer and injector, a novel data acquisition plan based on Ultra-deep resistivity LWD measurements and more conventional open hole measurements was designed to overcome these challenges. Ultra-deep directional resistivity measurements recorded in the injector well were used to map the reservoir structure and fluid distribution up to 100 feet above and below from the injector well. In addition to time lapse resistivity logging, a novel 2D deep azimuthal imaging using extended set of ultra-deep directional resistivity measurements with 3D sensitivities were used to identify movement of fluid in horizontal direction towards the producer well. Full 3D modeling of deep directional resistivity responses was performed before the data acquisition to evaluate sensitivities and signatures of invaded fracture swarms of variable fracture density on measurements and real-time interpretation based on 1D inversions.
The 2D deep azimuthal imaging using the extended 3D set of ultra-deep directional resistivity measurements provided resistivity maps used to identify the fluid fronts and evaluate movement of fluids in lateral direction and heterogeneities not only above and below but also left and right up to 100ft away from the wellbore. The identified flooded zones were consistent with time-lapse resistivities. The 3D modeling and 1D inversion helped to understand patterns in real-time deep directional resistivity interpretation. Detailed analysis of resistivity responses and original while drilling images confirmed identified fracture swarm zones. Besides overcoming challenges with conventional production logs, the methodology provides a unique 3D view of the reservoir from LWD logs at the scale of inches to 100ft.
The case study demonstrates the potential of newly developed deep azimuthal 2D imaging using ultra-deep directional resistivity data to refine the 3D structural interpretation and evaluate the fluid distribution up to 100 feet away from the injector well. This information will be critical to build for the first time consistent 3D interpretation from the wellbore to reservoir scale, calibrating 4D seismic in challenging Middle East carbonates reservoir and bridging the gap between the time-lapse conventional resistivity logs and 4D seismic.
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A Systematic Investigation of Surfactant/polymer Flooding in Conglomerate Reservoir: From Laboratory to Field Test
More LessSummaryConglomerate reservoir is characterized by high water cut, poor sweep efficiency and inefficient oil recovery during the end-period of water flooding. Surfactant/polymer (SP) flooding has been proved as one of the most promising CEOR methods to improve remaining oil recovery after water flooding, due to the unique synergy of polymer/surfactant. The mechanism and performance of SP flooding in conglomerate reservoir need be studied thoroughly.
We took Karamay oilfield, the biggest conglomerate pilot for SP flooding in China, as an example. Three critical issues, surfactant formulation, relationship between oil displacement and lithology, and filed adjustment methods based on development data, for successful SP flooding in conglomerate were investigated in this paper. Firstly, Petroleum sulfonate surfactant was extracted from Karamay crude oil and three properties including molecular structure and phase behavior were tested to optimize surfactant formations. Then the pore structure difference between conglomerates and sandstones was compared through thin section photographs and mercury-injection capillary pressure tests. Meanwhile, these typical cores of different lithology were used to conduct core flooding experiments, and pore-scale displacement of different concentrations of polymer and surfactant was also evaluated using nuclear magnetic resonance (NMR). After these laboratory researches, a pilot test (18 injection 26 production) at Karamay oilfield was performed in November 2011. Finally, technical issues related to scale-up and unique phenomena of development in conglomerate reservoir were discussed.
The complex of two anionic surfactants made surfactant solution achieve longer range of carbon number distribution, lower CMC and ultra-low interfacial tension with low concentration. Compared with sandstone, the diagenesis of conglomerates normally takes place in a shallower depth and then possesses more tortuous pore structures. Unlike sandstone cores, increasing polymer concentration cannot increase oil efficiency. The result of NMR test showed polymer flooding was hard to mobilize residual oil in pores whose radius was below 5μm. However, residual oil in these pores obviously decreased in SP flooding. For the pilot test, heterogeneous reservoir pressure and very low liquid production were observed in first 2 years. We had to stop some well group tests whose permeability was below 30mD and decrease molecular weight and concentration of polymer to continue testing in those wells (8 injection 13 production) whose permeability is relatively high. It has some good performances including appropriate emulsification, low water cut and high oil recovery (15.5%) until December 2016.
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Field Experience of Inorganic Gels Application with Cyclic Steam Stimulation
Authors I. Kuvshinov, L. Altunina and V. KuvshinovSummaryIn this paper we present the experience of using inorganic thermotropic gel-forming compositions, combined with cycle-steam stimulation of wells, at the Permian-Carboniferous deposit of the Usinsk oilfield, Russia, the Komi Republic, over the last 5 years. The compositions are aqueous solutions of salts with a viscosity close to water and are injected immediately before or at the initial stage of steam injection. Then, under the temperature of the injected steam, the composition forms a gel that ensures the leveling of the injectivity profile, the increase in the formation sweep by the steam, and the reduction of the water cut of the product. Inorganic gel based on aluminum salts, in contrast to many polymer compositions, is able to withstand high temperatures, typical for steam treatments, about 300 C.
The object under consideration, the Permian-Carboniferous deposit of the Usinsk oilfield is a carbonate fractured reservoir, characterized by a high oil viscosity, 710 mPa∙s, and a heterogeneous geological structure. The initial reservoir temperature is 23 C, which together with the high viscosity of oil gives the prerequisites for the application of thermal methods of recovery.
Over the past 5 years, from 2014 to the present, several dozens, and more recently, more than a hundred, of steam cyclic treatments are being conducted at the field in question. Of these, about 15–20 wells are treated annually with the use of inorganic thermotropic composition GALKA, in its different variations. The average oil production rate in the wells before treatment is 2–3 t/day, in the first month after treatment 15 t/day or more. Water cut before treatment is 85–95 %, after treatment with application of the composition and injection of steam is reduced by an average of 20 %, up to 65–75 %, whereas for steam treatments without reagents, an increase in water cut is observed, as the vapor condenses and is extracted along with oil in the form of water.
Also, it has been assumed that there is some critical, or optimal, well capacity by the amount of injected steam during steam cycling treatment, about 4–6 thousand tons for processing for a particular field. Exceeding this value does not increase the efficiency, but, on the contrary, can cause additional watering at the initial stage of extraction after processing. The use of gel-forming compositions increases steam coverage and reduces water cut, which allows to increase this critical capacity.
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Low Salinity and Immiscible CO2 Combined Flooding For Sandstone Reservoirs: Low Salinity-Alternating- CO2 Flooding (LS-CO2 WAG)
Authors H. Al-Saedi, R. Flori and W. Al-BazzazSummaryLow salinity (LS) water flooding and CO2 flooding are two new combination floods coupled due to the vital role of both in methods for increasing oil recovery. LS water was examined by many laboratory and field works, and it showed an impressive result in enhancing oil recovery. CO2 was tested on increasing oil recovery, and the oil recovery increased by improved wettability alteration effect towards more water-wet and interfacial tension reduction. Although CO2 showed an improvement in oil recovery, the density difference between CO2 and oil resulted in gravity override and channeling problems. LS water alternating CO2 flood gathers the benefits of LS itself to improve sweep efficiency by CO2, prevent the CO2 problems mentioned earlier, and capture the CO2 from the atmosphere. Furthermore, miscible CO2 flooding can reduce oil viscosity and trigger oil swelling. The laboratory experiments of all scenarios showed an incremental oil recovery, but the optimum scenario was the huff and puff-LS water-CO2-LS water scenario with additional oil recovery of 20.65% of OOIP. The three-hours huffing mobilized a new bank of oil, while the shorter LS water-CO2 cycles were the second optimum with incremental oil recovery 17.95% of the OOIP. This combination technology can solve the CO2 flooding problems and support CO2 by LS water, which in itself can increase oil recovery by altering the wettability towards more water-wet.
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Microfluidics Technology for Visualizing Surfactant Performance in Enhanced Oil Recovery
Authors J. Kim, E. Willmott and L. QuinteroSummaryThis paper introduces a microfluidic technology for surfactant evaluation for Enhanced Oil Recovery (EOR). During EOR surfactant development process, each developed surfactant formulation for a targeted reservoir must undergo oil recovery performance testing using conventional methods such as sandpack and coreflood test. Although these are beneficial testing tools, testing protocols and labor requirements can be quite time-consuming and expensive. The microfluidic system developed in this study accelerates surfactant selection process in a rapid, more convenient, and cost effective manner. It can be utilized as a fast screening tool to select candidate surfactant formulations for the final validation with core flood testing. It also offers superior visualization of oil-surfactant interactions to provide better understanding of what is occurring inside a reservoir that was not previously possible with conventional testing methods.
The newly developed microfluidic system utilizes porous media that resembles reservoir sandstone in terms of reservoir pore structure, wettability, and polarity. Initially, the porous media is filled with crude oil to be aged in-situ overnight at reservoir temperature and moderate pressure. Injection water is then injected into the porous media to simulate secondary recovery water flooding. For the residual oil left behind, a surfactant flood is injected, followed by additional water injection. The progression of oil recovery throughout the whole process is video recorded for visual assessment of surfactant performance. The collected images are analyzed to quantify the amount of oil recovery.
The experimental results confirmed that the microfluidic system can differentiate oil recovery performance among good, average, and poor performing surfactants. A systematic study showed that the microfluidic technique gives higher data resolution to differentiate surfactant performance than sandpack method and reasonable repeatability when wettability is controlled.
Furthermore, the details of oil recovery process inside porous media through the interaction between oil and surfactant and the formation of microemulsion is vividly exhibited in a transparent microfluidic reservoir. Depending on the surfactant type and efficacy, the effectiveness on oil recovery varies. This variation in surfactant performance was noticeable by comparing the digital images of residual oil in microfluidic porous media after flooding with different surfactants, enabling another level of chemical evaluation, which was not possible with conventional testing methods. The quantified oil recovery data was similar to those of conventional sandpack and core flood tests, but obtained faster by a few days up to a few weeks with less operational difficulty.
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Simulation Interpretation of Capillary Pressure and Relative Permeability from Waterflooding Laboratory Experiments in Preferentially Oil-wet Porous Media
Authors P.Ø. Andersen, K. Walrond, C. Nainggolan, E. Pulido and R. AskarinezhadSummaryIn preferential oil-wet porous media, water flooding laboratory experiments are prone to capillary end effects. The wetting oil phase will tend to accumulate at the outlet where the capillary pressure is zero and leavea high remaining oil saturation at steady state (defined by stable pressure drop and zero oil production rate) compared to the residual oil saturation. Andersen et al. (2017a) derived analytical solutions describing how capillary pressure and relative permeabilityof water (the injected phase) could be determined based on pressure drop and average saturation at steady states obtained at different water injection rates. Plotting these values against inverse rate reveal linear trends at high rates, with slopes and interceptsthat directly quantify the saturation functions in the range of negative capillary pressures. The method is similar to Gupta and Maloney0027;s (2016) intercept theory, but quantifies entire functions rather than a single point and provides the trends also at lowrates, thus utilizing all the information.
Our aim is to demonstrate how pressure drop and oil production at steady state for different water injection rates can be used to derive relative permeability and capillary pressure from water flooding. This is done inthree ways. First, synthetic waterflooding tests are generated (using the commercial software Sendra) applying the same saturation function correlations as assumed in the analytical solution. Then, more general correlations are assumed when generating thesynthetical data with Sendra. This , to test the robustness of the analytical solution of producing similar functions as the ‘true’ ones. Finally, we perform a waterflooding experiment in the lab on a high permeability (3 Darcy) Bentheimer sandstone core, alteredoil-wet using Quilon solution. The core was saturated with ~90 % n-decane oil and ~10 % brine. Spontaneous imbibition yielded << 1 % recovery. Forced imbibition of brine followed, starting from 0.4 PV/d, then increased stepwise after approaching steady stateuntil 12 rates had been applied, varied overall by a factor ~ 1000 to yield states governed by capillary forces and states governed by advective forces. The results were interpreted using both Sendra and the analytical solution.
The experimental procedure and model demonstrate that only water relative permeability and capillary pressure determine the steady state during water flooding and hence can be estimated accurately. The analytical solutioncould match the trends and magnitude simultaneously of steady state pressure drop and production with injection rate to give an estimation of the saturation functions. The estimates were as good as full history matching.
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Selection of Optimal Polyacrylamide for Polymer Flooding –Impact of Brine Composition and Reservoir Temperature
More LessSummaryHPAM is a copolymer of acrylamide and acrylic acid, and it is the most common polymer utilized in polymer flooding. Sulfonated polyacrylamides, i.e. copolymers of acrylamide and acrylamide tertiary butyl sulfonic acid (ATBS), are a potential choice for high temperature and harsh salinity reservoirs. The aim of this study was to provide systematic information to aid in the selection of most optimal type of polyacrylamide for polymer flooding, depending on reservoir temperature and injection brine composition. Specifically, two different types of polyacrylamides – HPAM and sulfonated – were compared.
The viscosity yield and long-term stability of selected HPAM and sulfonated samples were studied over a wide range of conditions: TDS (700 – 170 000 ppm), relative hardness (0–20 mol% of all cations), and temperature (25–120°C). The selected samples represent typical products often considered for polymer flooding. We provide landscape graphs for different sample types to visualize the effect of TDS, relative hardness and temperature to sample viscosity yield and long-term stability. The long-term stability was studied in various brine conditions by accelerated aging experiments at 83–120°C. Viscosity loss at these temperatures is mainly related to the hydrolysis reaction that turns acrylamide and ATBS groups into acrylic acid. Viscosity retention and hydrolysis rate (by 13C NMR) were followed throughout the aging experiments.
From the results it can be observed that HPAM type sample provides highest viscosity over a wide range of brine conditions at 25°C. Sulfonated samples provided higher viscosity than HPAM if temperature and/or relative brine hardness was high. Divalent cations in the brine have clear detrimental effect on HPAM viscosity. Similar relative hardness (mol% of cations) provides similar relative drop in viscosity (% viscosity loss compared to soft brine) over a wide range of TDS – i.e. the relative hardness can be considered even more informative value than the absolute content of divalent cations in ppm. The long-term stability becomes important at temperatures above ca. 50 – 60°C. The stability is affected by the reservoir temperature and brine quality. As the polymer hydrolyses, competing beneficial (increasing charge) and adverse (increasing interaction with divalent cations) effects are present, and their effect will vary from brine to brine. Sulfonation significantly improves long term stability.
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Evaluating Reservoir Fluids Geochemistry for Planning of Surfactant-Polymer Flooding
Authors I. Koltsov, A. Groman, S. Milchakov, N. Tretyakov, L. Panicheva, S. Volkova, E. Turnaeva and D. LenevSummaryGeochemistry of oils and fluids is often explored for understanding of basin origin and oil migration. Variability of fluids properties is also important for IOR\EOR projects, because critical parameters of chemical flooding, such as interfacial tension (IFT) and surfactant adsorption depend upon crude oil properties and brine composition. Understanding of geochemical and geological heterogeneity became even more important for project upscaling when large blocks or an entire field are proposed for chemical flooding.
This paper presents results of lab experiments with crude oils collected from several West Siberian oilfields which are considered as potential objects for surfactant-polymer (SP) flooding.
At first, paper describes which parameters are important for SP flooding compare to ASP. It is shown that SP technology requires the different set of parameters to be taken into account. For example, optimal salinity depends upon oil EACN, salinity of formation fluids, their hardness and, sometimes, balance between Ca\ Mg as the main hardness ions. Majority of mentioned parameters is routinely measured during waterflooding, but quality of data is sometimes questionable. Therefore interpretation could be a challenging task. Approaches for prudent interpretation are discussed, need for special sampling program is justified.
Variation of oils0027; EACN was investigated inside several oilfields. Standard geochemical parameters for oil composition (SARA) are also analyzed. Significant variation of oil parameters within several fields was discovered, especially in case of coproduction from different layers. Variation of optimal salinity for SP mixture as a function of fluids hardness was investigated in a lab. Changes in IFT around optimum were measured, possible correlations are proposed.
Finally, authors discuss how to use estimated variations in EACN, salinity and hardness for high-level modeling of chemical flooding. Regional and infield variations of oil properties were converted to a range of IFT values for a specific SP cocktail. Results allow further optimization of surfactant blends and reveal most important factors influencing efficiency of SP flooding and current technical strategy.
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Carbonated Water Injection in the North Sea Chalk Reservoirs: Energy Analysis and Environmental Assessment
More LessSummaryCarbon dioxide is one of the most effective fluids for improving and enhancing oil recovery. It dissolves in oil and reduces its density (i.e., swells the oil) and viscosity, giving oil a higher mobility. However, when the reservoir condition is not suitable for the CO2 to become miscible in oil, the high mobility and low density of the CO₂ causes channeling and gravity override, and as a result a poor sweep and early breakthrough. These problems can be addressed by dissolving the CO₂ in water, a fluid with lower mobility, and injecting it into the reservoir, known as carbonated water injection. It is observed experimentally that the injection of a water-soluble solvents such as CO₂ or DME into a chalk core (in tertiary mode) mobilizes a large fraction of the remaining oil and vastly improves the recovery factor. Moreover, the injected CO₂, if trapped in the reservoir, can mitigate the harmful impact of the CO₂ that is otherwise released to the atmosphere. This work tries to quantify the effectiveness of the carbonated water injection into a North Sea chalk reservoir in terms of the extra oil recovery, the overall process energy balance, and the net amount of stored carbon dioxide.
The prerequisite to a successful implementation of the carbonated water flooding is the availability of the CO₂. Different options are considered in this work, viz., pipeline transport of the captured CO₂ from the nearby fossil-fuel power plants, liquefied CO₂ transported by a ship, and the wind-farm electricity-driven separation of CO₂ from the atmosphere. All the energy requirements for the separation, transport, and injection of CO₂ are included in the energy analysis. The carbonated water injection into the chalk reservoir is modeled using an in-house finite volume solver. The amount of the stored CO₂ in the reservoir is quantified from the simulation results. It is assumed that the produced CO₂ in the production wells is separated and re-injected into the reservoir. The final results is presented as the net amount of recovered hydrocarbon energy from the reservoir and the net amount of captured CO₂ per unit recovered energy. The effectiveness of this process is compared to other CO₂ capture and storage processes in terms of the energy requirement per unit mass of captured carbon dioxide. The energy analysis in this work, which is founded on the fundamental laws of thermodynamics, can be easily converted to economic analysis.
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Dilute Surfactants for Wettability Alteration and Enhanced Oil Recovery in Carbonates
Authors S. Ayirala, A. Boqmi, A. Alghamdi and A. AlSofiSummaryThis experimental study evaluates the capability of dilute nonionic surfactants for wettability alteration and enhanced oil recovery applications in carbonates.Firstly the compatibility of surfactant was determined by performing aqueous stability tests in both low salinity and high salinity brines followed by surface tension measurements to determine critical micelle concentrations (CMC). Phase behavior, and interfacialtension measurements were conducted using 0.1 wt% surfactant and crude oil at reservoir temperature. The contact angle measurements were performed using carbonate surfaces and the nonionic surfactant at dilute concentrations to evaluate wettability alterationin carbonates at reservoir conditions. Zeta potential measurements were also carried out across calcite-brine/surfactant, and crude oil-brine/surfactant interfaces to confirm the wettability alterations induced by the surfactant. Lastly microscopic dynamicliberation experiments were conducted using dilute concentrations of surfactant and polymer chemicals in both high salinity and low salinity brines to quantify the effects of wettability alteration on oil liberation efficiency in carbonates.
The compatibility of nonionic surfactant was demonstrated in high salinity brine at reservoir temperature. The critical micelle concentrations were found to bevery low in the range of 0.0020 to 0.0025 wt% in both low salinity and high salinity brines. The phase behavior results showed the formation of middle phase microemulsion and correspondingly low interfacial tensions in the range of about 0.05 mN/m with 0.1wt% surfactant in high salinity brine. The contact angle data indicated the ability of nonionic surfactant to significantly alter the wettability of carbonate from oil-wet to either intermediate wet or less oil-wet in high salinity brine whereas only marginalwettability alterations from oil-wet to less oil-wet were obtained in low salinity brine. The increasing negative zeta potentials and the alteration of charge polarity from positive to negative were observed at crude oil-brine and calcite/brine interfaces,respectively, by using 0.1 wt% surfactant in the high salinity water. Such results confirm the effectiveness of nonionic surfactant in high salinity water to alter the wettability of carbonates at dilute concentrations. The microscopic equilibrium degree ofcrude oil liberation from carbonate surface was found to be about 20% higher with high salinity surfactant-polymer solution when compared to the low salinity surfactant-polymer solution. These consistent findings obtained from different experimental techniquesclearly point out that dilute nonionic surfactant combined with dilute polymer in conventional high salinity injection water can become one potential cost-effective chemical EOR solution for oil recovery in carbonate reservoirs.
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Gravity Assisted Steam Flooding (GASF) as a Post-CHOP for Foamy Extra-Heavy Oil Reservoirs
More LessSummaryExtra-heavy oil reservoirs in the Carabobo Area, the eastern Orinoco Belt, have been exploited with Cold Heavy Oil Production (CHOP) with horizontal wells utilizing foamy oil drive mechanism nowadays, with a primary recovery less than 12% OOIP. Steam flooding (SF) can effectively improve oil recovery factor of heavy oil reservoirs, but for horizontal wells the steam breakthrough and steam overlying are serious problems hindering the application of SF. Therefore the Gravity Assisted Steam Flooding (GASF) technology is presented. For GASF technology, the injector (vertical well or horizontal well) is laterally above the producer, so that the direction of steam flooding is laterally downward. The technical feasibility and adaptability of GASF processes are investigated in this study.
A representative sub-model of Block M located in the Carabobo Area was extracted to evaluate the performance of GASF. And some key issues including transfer time from cold production to GASF, appropriate well pattern, well spacing, and operation parameters were further discussed using the ideal numerical models. The study indicates that the technology of GASF could drastically increase the oil recovery of foamy extra-heavy oil reservoirs after cold production. The oil displacement mechanism of GASF includes steam flooding and gravity drainage. The best transfer time from cold production to GASF is when reservoir pressure drops down to the lower pressure during the cold production phase. For the homogeneous reservoir, the GASF with injector of horizontal well presents better performance. But if the heterogeneity reaches a certain degree, the GASF with injector of horizontal well will be inefficient, and the injector of GASF should be vertical well. Moreover, for GASF horizontal distance between injector and producer reduces, the oil recovery and oil steam ratio increases obviously. In addition, for GASF the vertical distance between injector and producer, the vertical injectors numbers, steam injection rate, and steam quality are discussed in this work.
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Experimental Investigation of Non-thermal EOR Methods for Foamy Extra-Heavy Oil Reservoirs
More LessSummarySome foamy heavy oil reservoirs in the eastern Orinoco Heavy Oil Belt in Venezuela have been developed for decades by the foamy oil cold production method. The oil production rate declines obviously with reservoir pressure depletion. It should be carried out with consideration of a follow-up method to increase the ultimate oil recovery. Whereas the completion method of a great many production wells is not suitable for steam based recovery technology. Therefore a series of non-thermal EOR methods were investigated.
In this work, the viscosity of dead oil is 14500 mPa•s (53.7℃) and the produced gas is mainly comprised of methane and CO2 (87:13 in molar ratio). The flooding EOR methods of water flooding, produced gas flooding, surfactant flooding, and foam flooding; the huff and puff EOR methods of produced gas huff and puff , viscosity reducer assisted produced gas huff and puff, and foaming agent assisted produced gas huff and puff were conducted through microscopic visualization and sandpack displacement experiments.
Experimental results show that the for the flooding EOR methods, due to the tremendous mobility ratio, the water flooding and produced gas flooding get poor EOR performance. The surfactant flooding can improve the oil recovery factor by 15.09% because the surfactant reduces the interfacial tension and increases displacement efficiency. Furthermore the foam flooding can improve the oil recovery factor by 24.06% because the foam increases both the displacement efficiency and the sweep efficiency. For huff and puff EOR methods, produced gas huff and puff can improve the oil recovery factor by 7.4%, and microscopic visualization experiment shows the secondary foamy oil is generated after produced gas dissolved in oil phase. The viscosity reducer assisted produced gas huff and puff can improve the oil recovery factor by 12.5% owing to the reduced oil viscosity and improved oil mobility. The foaming agent assisted produced gas huff and puff can improve the oil recovery factor by 18.2%. That is because the foaming agent helps to form secondary foamy oil and keep the produced gas dispersed in the oil phase as long as possible.
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The Effects of Crossflow and Permeability Variation on Different Miscible CO2 injection Schemes Performance in Layered Sandstone Porous Media
Authors D. Al-Bayati, A. Saeedi, C. White, Q. Xie and M. MyersSummarySupercritical carbon dioxide (SCCO2) injection in hydrocarbon reservoirs is documented as important means to achieve hydrocarbon potential whilst mitigating the greenhouse gas effect. However, reservoir heterogeneity significantly affects subsurface multiphase flow behaviour thereby oil recovery factor, thus triggering intrinsic uncertainties to manage and predict reservoir performance. In this manuscript, we present the results of a systematic approach to investigate the influences of crossflow and permeability variations in layered core samples on the efficiency of miscible continuous SCCO2 and water alternating gas (WAG) flooding performance. Here, we manufactured heterogeneous porous media by stacking two hemi cylindrical sample (each sample has a different permeability) together. Placing either a lint free tissue paper or a Teflon sheet allowed us to investigate the impact of crossflow on displacement efficiency. The core flooding experiments were conducted under miscible conditions at a reservoir temperature of 343 K and pressure of 17.23 MPa using n C10, synthetic brine and SCCO2. Two different SCCO2 flooding schemes were used; namely, continuous injection of SCCO2 and water alternating SCCO2.
The results obtained from heterogeneous porous media indicate that permeability variations in layered porous media have significantly impact the ultimate recovery for both continuous and WAG flooding. It is also found that crossflow in the layered sample has an appreciable effect on the ultimate oil recovery (i.e. increasing oil recovery by 4.8% as a maximum) when injecting SCCO2 continuously. However, as the permeability variations between layers increases a considerable channelling of the injected SCCO2 through the high permeability layer is dominated which reduces the amount of additional oil mobilised by crossflow. In contrast to the findings of continuous injection of SCCO2, the effect of crossflow during WAG flooding is negatively impacts the recovery factor. Such an outcome by WAG flooding may be attributed to the achievement of conformance control under the non communication layers which otherwise cannot due to occurrence of preferential flow paths. Thus, the results of this study provide insight into the importance of crossflow in layered porous media to overcome the current challenges in capturing the importance of geological uncertainties in the current and future SCCO2 IOR/EOR projects.
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