Waterflooding Experiments Research Articles

Effect of pore structure and injection pressure on waterflooding in tight oil sandstone cores using NMR technique and pore network simulation

As an economical and reusable method of enhancing oil recovery, waterflooding is widely used in the development of tight oil reservoirs, although it has often been found unsuccessful owing to the adverse properties of tight rocks. Accurate knowledge of the pore-scale distribution of oil in tight rocks during waterflooding is needed for devising strategies to maximize oil recovery. Here, we used a two-fold approach to identify the amount and spatial distribution of the residual oil as a function of injection pressure. We i) characterized the pore structure of two cores from a tight sandstone reservoir in the Ordos basin, China, and ii) conducted waterflooding experiments with different injection pressures using nuclear magnetic resonance measurements. We found that even small differences in the tight sandstones pore structures caused measurable variations of the amounts oil produced from different classes of pores. For example, in experiments using identical water injection pressures but samples with different permeabilities, a permeability increase by a factor of 3 corresponded to a 10% reduction in oil recovery. We also found that the increase in residual oil saturation caused by increasing the injection pressure was unfavorably dependent on the pore structure heterogeneity. This observation was supported by pore network simulations, which were additionally carried out. We therefore conclude that it is necessary to evaluate the pore structure heterogeneity of the reservoir rocks when attempting to enhance the oil recovery factor of a tight reservoir by means of the common strategy of raising the waterflood injection pressure.

Flow behaviors and residual oil characteristics of water flooding assisted by multi-effect viscosity reducer in extra heavy oil reservoir

Although waterflooding treatment assisted by traditional viscosity reducer yields additional oil recovery, this increments in production sometimes cannot meet the production requirements. To solve this problem, it is necessary to analyze and understand the flow mechanism of heavy oils in the waterflooding process assisted by the viscosity reducer. This study employed an etched glass micro-model to visualize the flow behavior of heavy oils under assistance of a novel multi-functional viscosity reducer with the condition of high temperature and ultra-heavy oil. The water flooding and novel viscosity reducer flooding experiments were carried out, and the state and shape of the remaining oil phase were observed from the global perspective and the microscopic local perspective in the etching micro-glass. Results show that the viscosity reducer solution can not only greatly reduce viscosity of heavy oil but also decrease oil-water interface tension. In the waterflooding process, the continuous oil group and long oil slug are the main characteristics of remaining heavy oil in the reservoir. By waterflooding with the new viscosity-reducer, the remaining oils exist as short slug and droplet, and 3 times wider flooding area for fluid-flow was observed than conventional waterfloodings.

Experimental Study on Water-Plugging Performance of Silicon Dioxide/Polystyrene Hydrophobic Insoluble Microsphere Particle Flooded by High-Water-Cut Oil–Water Mixture

Abstract Water plugging was an important but difficult process close to high-water-cut production wells. The injected water-plugging materials were usually liquid and typically had been evaluated by conventional water-flooding experiments. In this study, silicon dioxide (SiO2)/polystyrene hydrophobic insoluble microsphere particles were introduced as a selective water shutoff agent, and the water-saturated core was flooded with a high-water-cut oil–water mixture. Indexes such as modified oil-coning time, water-cut fluctuation, and cumulative water cut were proposed to evaluate water-plugging capability. A parametric study was conducted to evaluate the influence of particle composition (A, SiO2/polystyrene particle; B, complete polystyrene particle), water cut of the injected oil–water mixture, and preheating temperature of the insoluble particles on water-plugging performance. The results from the index analysis and relative permeability curve showed that the proposed indexes could be used to compare water-plugging performance during oil–water mixture drive; both particles had better water-plugging performance when the injected mixture was not an ultrahigh water cut (fw < 90%). Particle B had larger lipophilicity and stronger capacity for decreasing the water cut (about 0.55–1.28%) at a conventional temperature when the oil–water mixture of the injected fluid had a water cut of 90%. Particle A had lower capacity to decrease the water cut (by about −0.94–0.26%), but it was resistant to reservoir temperature because of its dense structure and the addition of SiO2. These results provided suggestions for the application of hydrophobic insoluble microsphere particles in water plugging in production wells.

Heterogeneity of pore-throat structures and petrophysical properties of tight sandstone and its influence on seepage: A case study of sandstone in the Yanchang Formation, Ordos Basin, China

Tight sandstone reservoirs are characterized by poor petrophysical properties, strong pore-throat structures, and heterogeneous permeability, which prevent oilfield water flooding. We take the tight sandstone reservoir of the Yanchang Formation in Ordos Basin as an example, select samples from the Chang 6 and Chang 8 members in the HX block for constant-rate mercury injection and single-core and combined-core model water-flooding tests, and discuss the effects of heterogeneous pore-throat structures and petrophysical properties on the seepage of the tight sandstone. Constant-rate mercury injection tests found that the permeability of the tight sandstone was controlled by the throats. Compared with the pore structures, the throat structures were more heterogeneous, and the samples with more heterogeneous throats were more permeable. Therefore, in addition to the morphology of the pore-throat structures, the heterogeneity of the throats also was used to evaluate the seepage. When applying the water-flooding tests with the combined-core model, the water absorption capacity of the high-permeability core with a high permeability contrast (7.5) was greater than that of the high-permeability core with a low permeability contrast (3.6). Moreover, by comparing the results from the water-flooding experiment for the same core between a single-core and the combined-core model, the loss of the oil displacement efficiency (70.7%) of the low-permeability core in the combined-core model with a high permeability contrast (7.5) was much higher than that (29.8%) of the low-permeability core in the combined-core model, which had a low permeability contrast (3.6). The water absorption percentage and the recovery of the low-permeability core in the combined-core model with a high permeability contrast were lower, indicating that after water flooding, the remaining oil in the low-permeability reservoir in the area with a strong permeability heterogeneity was enriched. Such enrichment may increase the exploitation potential of tight reservoirs.

Gas and water distribution characteristics of water-driven gas process in tight sandstone gas reservoirs: A microscale study by molecular simulation and experiment

Predicting gas and water distribution is an essential step in developing gas reservoirs. This study aims to study the characteristic distribution law of gas and water during waterflooding, which are important in wettability alteration to enhance gas reservoir recovery. Herein, we report a novel method that uses molecular dynamics (MD) associated with a microscopic waterflooding experiment to obtain the characteristic distribution law of gas and water in porous media. We show that this approach may better understand the relationship between gas and water in porous media than conventional technologies. The waterfront in the hydrophilic channel is 13.3 Å more advanced than that in the neutral channel, indicating that the water displacement efficiency in hydrophilic channels exceeds that in neutral channels. Meanwhile, the water flows mainly along the walls of the pores and reduces the diameter of the permeate channel in hydrophilic porous media. While in neutral porous media, the above phenomenon is significantly weakened, and the waterflooding front is relatively consistent. Most importantly, the experimental and simulation results are consistent, and a quantitative evaluation of the gas–water distribution in porous media is given. Additionally, technologically, wettability directly affects the distribution characteristics of fluids in porous media, and changing the wettability characteristics of reservoir rocks is beneficial to delaying the waterflooding front. This approach provides an essential theoretical basis for developing water-driven gas reservoirs.

Using high-intensity water flooding relative permeability curve for predicting mature oilfield performance after long-term water flooding in order to realize sustainable development

Most of the mature oilfields are on the verge of being abandoned. Drilling infill wells or chemical displacement is a standard method to improve mature oilfield performance. But these methods are not economical. For the sustainable and economic development of mature oilfields, large displacement natural water flooding was applied for improving mature oilfield performance. After high-intensity water flooding, most of the mature oilfields are in high water-cut and high recovery stages, and it is difficult for performance prediction. Relative permeability is an important characteristic of multiphase flow in porous media and also an important parameter for dynamic prediction of high water cut stage. In this study, the ratio of the flow-through water flow to the pore area of the displaced cross-section, i.e., the displacement flux (P.A.), was applied to characterize the scouring intensity. Two types of relative permeability curves were obtained through high-intensity water flooding (HIWF) experiments, including one type of continuous relative permeability curve of different displacement fluxes (Type I HIWF relative permeability curve) and the second type of multiple relative permeability curves of different displacement fluxes under re-saturated conditions (Type II HIWF relative permeability curve). In addition, a two-dimensional five-point pattern model was established to compare the calculation results of one conventional type of relative permeability curve and two types of HIWF relative permeability curve. Finally, a numerical model of a real reservoir in a mature oilfield was generated to test the method. The results demonstrate that using Type I HIWF relative permeability curve is fast and accurate to characterize the performance of the ultra-high water cut stag, which guides the application of high-intensity long-term water flooding in order to improving the ultimate oil recovery (IOR). So as to help the mature oilfields achieve economic and sustainable development.

An insight into core flooding experiment via NMR imaging and numerical simulation

Traditional core flooding experiments can only be used post breakthrough while what happens in the core prior to this time is vital to understand multiphase flow phenomenon for more successful EOR operations. We can overcome this obstacle through a visualized fluid displacement scheme. This can ultimately provide us with a reliable relative permeability curve that can lead to a more accurate reservoir simulation outcome in the field scale. In this study, NMR imaging is employed in a water flood experiment in conjunction with two separate numerical two-phase flow simulation methods (FDM and FEM), to reproduce experimental data. Using the Brooks-Corey equation, random pore size distribution indices (λ) are selected to generate relative permeability curves. Moreover, simulations are performed with FDM, and oil displacement efficiency, saturation maps, and saturation profiles are generated and compared to the experimental results. Next, FEM was employed in COMSOL for further validation and FDM results were found in agreement with the experiments. This way, an appropriate relative permeability curve was generated and assigned to the sample. Results suggest that λ of 0.2 generated the best numerical results with an MSE value of 0.009 in oil displacement efficiency curves, comparable to the experiments. Collectively, integration of imaging techniques with routine experimental fluid displacement procedures presented a detailed insight into complicated nature of multiphase flow phenomena in geomaterials.

Experimental study on the oil production characteristics during the waterflooding of different types of reservoirs in Ordos Basin, NW China

Waterflooding experiments were conducted in micro-models (microscopic scale) and on plunger cores from low permeability, extra-low permeability and ultra-low permeability reservoirs in the Ordos Basin under different displacement pressures using the NMR techniques to find out pore-scale oil occurrence state, oil production characteristics and residual oil distribution during the process of waterflooding and analyze the effect of pore structure and displacement pressure on waterflooding efficiency. Under bound water condition, crude oil mainly occurs in medium and large pores in the low-permeability sample, while small pores and medium pores are the main distribution space of crude oil in extra-low permeability and ultra-low permeability samples. During the waterflooding, crude oil in the medium and large pores of the three types of samples are preferentially produced. With the decrease of permeability of the samples, the waterflooding front sequentially shows uniform displacement, network displacement and finger displacement, and correspondingly the oil recovery factors decrease successively. After waterflooding, the residual oil in low-permeability samples is mainly distributed in medium pores, and appears in membranous and angular dispersed phase; but that in the extra-low and ultra-low permeability samples is mainly distributed in small pores, and appears in continuous phase formed by a bypass flow and dispersed phase. The low-permeability samples have higher and stable oil displacement efficiency, while the oil displacement efficiency of the extra-low permeability and ultra-low permeability samples is lower, but increases to a certain extent with the increase of displacement pressure.

Using High-Intensity Water Flooding for Improving Mature Oidfield Performance for Sustainable Development

Most of the mature oilfields are on the verge of being abandoned. Drilling infill wells or chemical displacement is a standard method to improve mature oilfield performance. But these methods are not economical. For the sustainable and economic development of mature oilfields, large displacement natural water flooding was applied for improving mature oilfield performance. After high-intensity water flooding, most of the mature oilfields are in high water-cut and high recovery stages, and it is difficult for performance prediction. In this study, the displacement flux (P.A.), was applied to characterize the scouring intensity. Two types of relative permeability curves were obtained through high-intensity waterflooding (HIWF) experiments, including one type of continuous relative permeability curve of different displacement fluxes and the second type of multiple relative permeability curves of different displacement fluxes under re-saturated conditions. In addition, a two-dimensional five-point pattern model was established to compare the calculation results. Finally, a numerical model of a real reservoir in a mature oilfield was generated to test the method. The results demonstrate that using the type I relative permeability curve is fast and accurate to characterize the performance of the high water cut stage for sustainable development.

Mathematical Model for Water Flooding and HPAM Polymer Flooding in Enhanced Oil Recovery

The need for energy, especially the petroleum-based one, is steadily increasing along with population growth and technological advancement. Meanwhile, oil exploitation from oil reservoirs using primary and secondary techniques can only obtain about 30%-50 % out of the original oil in place. Enhanced Oil Recovery (EOR) is a method for increasing oil recovery from a reservoir by injecting materials that are not found in the reservoir, such as surfactant, polymer, etc. This research aims to develop a mathematical model representing two-phase flow through porous media in the EOR process. This model was extended from mass balance and fluid flow in porous media equations. The reliability of the model was then validated by water flooding and polymer flooding experiment. A porous media, constituted by a silica sand pack, was saturated with 2 % brine and sequentially flooded with HPAM polymer solution at various concentrations (5,000-15,000 ppm). The volume of the oil coming out from the media at any time intervals was measured. Validation of the model was carried out by optimizing the model parameters to obtain the best curve-fitting on the plot of the percentage of cumulative recovered oil against time. The results showed that the proposed mathematical model was reliable enough to express both water and polymer-flooding processes.

Pore-by-Pore Modelling, Validation and Prediction of Waterflooding in Oil-Wet Rocks Using Dynamic Synchrotron Data

We predict waterflood displacement on a pore-by-pore basis using pore network modelling. The pore structure is captured by a high-resolution image. We then use an energy balance applied to images of the displacement to assign an average contact angle, and then modify the local pore-scale contact angles in the model about this mean to match the observed displacement sequence. Two waterflooding experiments on oil-wet rocks are analysed where the displacement sequence was imaged using time-resolved synchrotron imaging. In both cases the capillary pressure in the model matches the experimentally obtained values derived from the measured interfacial curvature. We then predict relative permeability for the full saturation range. Using the optimised contact angles distributed randomly in space has little effect on the predicted capillary pressures and relative permeabilities, indicating that spatial correlation in wettability is not significant in these oil-wet samples. The calibrated model can be used to predict properties outside the range of conditions considered in the experiment.

Isolating, identifying and evaluating of oil degradation strains for the air-assisted microbial enhanced oil recovery process.

Due to the inefficient reproduction of microorganisms in oxygen-deprived environments of the reservoir, the applications of microbial enhanced oil recovery (MEOR) are restricted. To overcome this problem, a new type of air-assisted MEOR process was investigated. Three compounding oil degradation strains were screened using biochemical experiments. Their performances in bacterial suspensions with different amounts of dissolved oxygen were evaluated. Water flooding, microbial flooding and air-assisted microbial flooding core flow experiments were carried out. Carbon distribution curve of biodegraded oil with different oxygen concentration was determined by chromatographic analysis. The long-chain alkanes are degraded by microorganisms. A simulation model was established to take into account the change in oxygen concentration in the reservoir. The results showed that the optimal dissolved oxygen concentration for microbial growth was 4.5~5.5mg/L. The main oxygen consumption in the reservoir happened in the stationary and declining phases of the microbial growth systems. In order to reduce the oxygen concentration to a safe level, the minimum radius of oxygen consumption was found to be about 145m. These results demonstrate that the air-assisted MEOR process can overcome the shortcomings of traditional microbial flooding techniques. The findings of this study can help for better understanding of microbial enhanced oil recovery and improving the efficiency of microbial oil displacement.

Recovery of viscous and heavy oil by CO2-saturated brine

Fast economic growth in Oman coupled with its climatic conditions have led to an energy-intensive lifestyle that has resulted in high levels of carbon dioxide (CO2) emissions. The injection of CO2 produced by cement plants into oil reservoirs combined with carbon capture is seen as an option to reduce CO2 in the air in order to curb climate change. The potential of CO2-saturated brine to recover oil is investigated using two samples of viscous oil (13 and 21 cP) and one sample of heavy oil (1471 cP) from Oman in water flooding experiments followed by CO2-saturated brine injection at 25 °C and 3.45 MPa. CO2 solubility in oil and brine, changes of their viscosity and density, oil swelling and other parameters are investigated.Irrespective of early water breakthrough, the greatest incremental recovery of 25.6% after injection of CO2-saturated brine through oil saturated core is obtained for heavy oil, as compared to 8.2% and 15% for viscous oils. Higher recovery from heavy oil sample is explained by the greater viscosity reduction in addition to the density reduction of CO2-saturated oil that is similar for all three types of oil of about 50% on average. The greatest reduction of oil viscosity of 87% is obtained for the heavy oil and 59% on average for viscous oil samples. Thus, different mechanisms contribute more into the oil recovery: density reduction due to oil swelling for viscose oil and viscosity reduction for heavy oil.The injection of CO2-saturated brine demonstrates a great potential in addressing both issues, curbing of climate change and energy supply by enhanced recovery of viscous and heavy oil.

Microbial-derived bio-surfactant using neem oil as substrate and its suitability for enhanced oil recovery

The limitation in the formulation and application of synthetic surfactants in petroleum industry is owing to their high cost of production or importation and their associated toxic effect which have been proven to be harmful to the environment. Hence it is vitally imperative to develop an optimum surfactant that is cost-effective, environmentally safe (biodegradable) and equally serves as surface acting agent. This study discusses the production of microbial produced bio-surfactant and its application in enhanced oil recovery. The bacteria Pseudomonas sp. were isolated from urine and allow to feed on neem seed oil as the major carbon source and energy. The crude bio-surfactant produced from the fermentation process was used to prepare three (3) solutions of bio-surfactants at different concentrations of 5 g/500 mL, 10 g/500 mL and 15 g/500 mL, and their suitability for enhanced oil recovery (EOR) was evaluated. Reservoir core samples and crude oil collected from the Niger Delta field were used to evaluate the EOR application of the microbial-derived surfactants. The sets of experimental samples were carried out using core flooding and permeability tester equipment, and the results obtained were compared with conventional waterflooding experiments. The three bio-surfactant concentrations were observed to recover more oil than the conventional waterflooding method for the two core samples used. Optimum performance of the produced microbial-derived surfactant on oil recovery based on the concentrations was observed to be 10 g/500 mL for the two samples used in this study. Therefore, eco-friendly bio-surfactant produced from neem seed oil using Pseudomonas sp. has shown to be a promising potential substance for enhanced oil recovery applications by incremental recoveries of 51.9%, 53.2%, and 29.5% at the concentration of 5, 10, and 15 g/500 mL and 24.7%, 28.7%, and 20.1% at concentration of 5, 10, and 15 g/500 mL for the two core samples, respectively.

Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions

Using micro-CT imaging and differential pressure measurements, we design a comparative study in which we simultaneously measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. This allows us to isolate the impact of wettability on a pore-by-pore basis and its effect on the macroscopic parameters, capillary pressure and relative permeability, while keeping the pore-space geometry unchanged.First, oil and brine were injected through a water-wet reservoir sandstone sample at a fixed total flow rate, but in a sequence of increasing brine fractional flows with micro-CT scans of the fluid phases taken in each step. Then the sample was brought back to initial water saturation and the surface wettability of the sample was altered after prolonged contact with crude oil and the same measurement procedure was repeated on the altered-wettability sample which we call mixed-wet.Geometric contact angles were measured, which discriminated the water-wet and mixed-wet cases with average values of 75° and 89° respectively. Additionally, an energy balance was used to determine the effective contact angles for displacement which indicated that a higher advancing contact angle of 116° was needed to displace oil in the mixed-wet case. For the water-wet experiment the filling sequence was pore-size dependent, with a strong correlation between pore size and oil occupancy. However, in the mixed-wet experiment the principal determinant of the filling sequence was the wettability rather than the pore size, and there was no correlation between pore size and the residual oil occupancy.The oil-water interfacial area had a larger maximum in the mixed-wet case which was supported by the observation of sheet or saddle-like menisci shapes present throughout the sample volume that impede the flow. These shapes were quantified by much larger negative Gaussian curvature which indicated better connectivity of the phases, consistent with the lower residual oil saturation. Mean curvature and associated capillary pressure were positive for the water-wet case but decreased to a negative value for the mixed-wet case pointing to forced displacement from oil-wet pores. This analysis explained why the relative permeabilities for the mixed-wet case were lower than for the water-wet case for the same fractional flow.

Experimental Research on the Optimization and Evaluation of the Polymer/Chromium-Ion Deep Profile Control System for the Fractured Low-Permeability Reservoirs

The matrix/fracture conductivity of a fractured low-permeability reservoir is variable, and its heterogeneity is serious. When carrying out deep profile control measures, it is difficult to inject under the premise of ensuring the plugging effect. According to the characteristics of the fractured low-permeability reservoir in Chaoyanggou Oilfield, the polymer/chromium ion deep profile control system was optimized via a viscosity evaluation experiment, liquidity experiment and oil displacement experiment. The experimental results show that the high molecular weight main agent/low concentration system and low molecular weight main agent/high concentration system can meet the gel strength requirement. The evaluation results of the injection ability and plugging performance of the fractured low-permeability core show that a high molecular weight profile control system is difficult to inject, while a low molecular weight profile control system has a poor plugging performance and high cost after simulated shear. Therefore, the formulation of the profile control system was determined to be a polymer with a molecular weight of 16 million g·mol−1 as the main agent with a concentration of 1000–1500 mg·L−1. As assisting agents, the concentrations of thiourea, NaCl and NaHCO3 were 900 mg·L−1, 800 mg·L−1 and 700 mg·L−1, respectively. The plugging rate of the system was 87.6%, and the resistance coefficient was 19.2. Finally, a fractured low-permeability core model with parallel long cores was designed, and the optimal profile control system was used for the core oil-displacement experiment. Compared with the water-flooding experiment, the plugging rate can be increased by 6.9–8.0%.

Occurrence state and forming mechanism of microscopic remaining oil controlled by dynamic and static factors

In order to reveal the occurrence state and forming mechanism of multi-type microscopic remaining oil controlled by both static reservoir factors and dynamic development factors, cores of the alluvial fan reservoir in the eastern steep slope zone of the Cangdong sag, the Bohai Bay Basin, China was selected, and then the occurrence state of multi-type microscopic remaining oil was quantitatively characterized and the forming process and mechanism of multi-type microscopic remaining oil was discussed based on waterflooding experiments on glass etching models and CT scanning on waterflooding process in real cores, and the basic classification of microscopic remaining oil. The results show that the two-dimensional microscopic remaining oil as individual oil blocks can be divided into two movable types -- isolated and semi-filled in pores, two adhering types – to pore walls and pore corners, and two retained types –in pores and throats. The three-dimensional microscopic remaining oil as accumulated oil blocks can be divided into three types, including cluster remaining oil, droplet remaining oil and flocculent remaining oil. The greater the permeability, the weaker the heterogeneity, the greater the waterflooding rate and the more displacement along the paleocurrent direction, the more the retained remaining oil tends to be movable. Changing the measures of dynamic water injection, the remaining oil retained in pores is the easiest to be recovered, followed by the remaining oil retained in throats and that semi-filled in pores. The movable remaining oil is formed when oil blocks are dispersed or gradually peeled off after being swept by injected water; the adhering remaining oil is formed when the part between oil block and pore wall or corner does not overcome its friction and capillary force and adheres to pore wall or corner; the retained remaining oil is the result that oil blocks are not swept or driven because of the bypassing injected water. The microscopic remaining oil as accumulated oil blocks is the aggregation of the microscopic remaining oil as independent oil blocks in a three-dimensional space.

Visualized Experiments on Residual Oil Classification and Its Influencing Factors in Waterflooding Using Micro-Computed Tomography

Abstract Pore-scale mechanism of the waterflooding process contributes to enhanced oil recovery, which has been widely emphasized in the petroleum industry. In this paper, pore-scale waterflooding experiments are carried out on mixed-wetted natural sandstone and 3D printed sandstone using micro-computed tomography (μ-CT). The high-resolution images of oil/water distribution in different stages of waterflooding cycles are acquired. The classification of residual oil after waterflooding is conducted using the shape factor and Euler number, which represents the shape and spatial connectivity, respectively. The in situ contact angles are measured on the segmented images and the pore-scale wettability of these two samples is analyzed. Then, the effects of pore structure, micro-fracture and wettability on the distribution of the patterns of residual oil are analyzed. The results indicate that the types of isolated, cluster, network, and film (only for natural sample) are the main forms of residual oil patterns after the waterflooding process. The negative correlation between the shape factor and the Euler number of the typical oil blocks are presented. The effect of wettability and pore geometry on the morphology of the oil/water interface is quantitatively studied. The capillary pressure is the key factor for the formation of the residual oil blocks, the morphology of which is controlled by both wettability and pore geometry.

An experimental and numerical study of low salinity effects on the oil recovery of carbonate rocks combining spontaneous imbibition, centrifuge method and coreflooding experiments

Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low-salinity effect, spontaneous imbibition and/or waterflooding experiments have been reported. This paper combines spontaneous imbibition, centrifuge and unsteady state (USS) coreflooding experiments to investigate low-salinity effects in carbonate samples.The experimental study used three brine compositions to investigate low-salinity effects. A high-saline Formation-water (salinity of 183.4 g/l), Sea-water (43.8 g/l) and 100-times Diluted-sea-water (0.4 g/l). Initially, a sequence of spontaneous imbibition experiments was conducted to screen the impact of connate and imbibing water composition on spontaneous oil recovery. After completing the spontaneous imbibition tests, the samples were drained inside a centrifuge to determine the impact of brine composition on residual saturation and capillary pressure. Moreover, three USS corefloodings were conducted to test the different brine compositions in secondary and tertiary injection mode. The spontaneous imbibition, centrifuge method and coreflooding tests showed a consistent trend. Compared to Formation-water and Sea-water, Diluted-sea water demonstrated the most promising potential to recover oil efficiently.The numerical part of the study includes the transparent development of a numerical centrifuge and coreflooding model on the top of the open-source simulator DuMux. The mathematical model formulation demonstrates that a simple numerical approach is sufficient to history match the centrifuge and coreflooding experiments. In line with the experimental data, the numerically derived capillary pressure and relative permeability showed an increasing water-wetting behavior as the salinity of the imbibing/injection water decreased. All implemented numerical models were validated against the commercially established Cydar software.

Studying of parameters of two-phase displacement in porous media with MRI technique

This study describes experimental research on two-phase flow displacement using Magnetic Resonance Imaging (MRI) techniques. The overall purpose of this investigation is to determine kinetics process of phase trapping during (water-oil) two-phase flow, the front deformation and the phases saturation propagation along a vertical model. In these water flooding experiments, the porous medium model consists of packed beads of polystyrene (0.4 mm < dp < 0.6 mm) or sand grains (0.02 mm < dp < 0.50 mm). In order to conduct high accuracy experiments, a Nuclear Magnetic Resonance (NMR) spectrometer operating at 14 T (corresponding to a 600 MHz 1H resonance) equipped with an imaging device was used. With this equipment we can measure and visualize the two-phase flow in a vertical model of porous medium under ambient conditions. The obtained results have shown that the oil saturation profile is strongly influenced by the material properties such as the phase wetting, the sample porosity and permeability as well as the injection rate. The influence of flow velocity on the residual oil saturation was also studied. The experimental results allow an essential understanding of immiscible fluid displacement in two different types of porous medium that differ from each other mainly by the effects of wettability.