A Novel Trilinear Flow Model for Capturing Dynamic Behavior of Water Flooding in Core Plug with Different Fracture Inclinations in Carbonate Reservoirs

The purpose of this study is to introduce a new three-linear flow model for capturing the dynamic behavior of water flooding with different fracture occurrences in carbonate reservoirs. Low-angle and high-angle fractures with different occurrences are usually developed in carbonate reservoirs. It is difficult to simulate the water injection development process and the law of water flooding is unclear, due to the large variation of the fracture dip. Based on the characteristics of water flooding displacement streamlines in fractured cores with different occurrences, the matrix is discretized into a number of one-dimensional linear subregions, and the channeling effect between each subregion is considered in this paper. The fractures are divided into the same number of fracture cells along with the matrix subregion, and the conduction effect between the fracture cells is considered. The fractured core injection-production system is divided into three areas of linear flow: The injected fluid flows horizontally and linearly from the matrix area at the inlet end of the core to the fracture and then linearly diverts from the fracture area. Finally, the matrix area at the outlet end of the core also presents a horizontal linear flow pattern. Thus, a trilinear flow model for water flooding oil in fractured cores with different occurrences is established. The modified BL equation is used to construct the matrix water-flooding analytical solution, and the fracture system establishes a finite-volume numerical solution, forming a high-efficiency semianalytical solution method for water-flooding BL-CVF. Compared with traditional numerical simulation methods, the accuracy is over 86%, the model is easy to construct, and the calculation efficiency is high. In addition, it can flexibly portray cracks at any dip angle, calculate various indicators of water flooding, and simulate the pressure field and saturation field, with great application effect. The research results show that the greater the fracture dip angle, the higher the oil displacement efficiency. When the fracture dip angle is above 45°, the fracture occurrence has almost no effect on the oil displacement efficiency. The water breakthrough time of through fractures is earlier than that of nonthrough fractures, and the oil displacement efficiency and injection pressure are more significantly affected by the fracture permeability. With the increase of fracture permeability, the oil displacement efficiency and the injection pressure of perforated fractured cores dropped drastically. The findings of this study can help for better understanding of the water drive law and optimizing its parameters in cores with different fracture occurrences. The three-linear flow model has strong adaptability and can accurately solve low-permeability reservoirs and high-angle fractures, but there are some errors for high-permeability reservoirs with long fractures.

Screening of Surfactants for Flooding at High-Mineralization Conditions: Two Production Zones of Carbonate Reservoir

The selection of effective surfactants potentially can mobilize oil up to 50% of residuals in mature carbonate oilfields. Surfactants’ screening for such oilfields usually is complicated by the high salinity of water, high lipophilicity of the rock surface, and the heterogeneous structure. A consideration of features of the oilfield properties, as well as separate production zones, can increase the deep insight of surfactants’ influence and increase the effectiveness of surfactant flooding. This article is devoted to the screening of surfactants for two production zones (Bashkirian and Vereian) of the Ivinskoe carbonate oilfield with high water salinity and heterogeneity. The standard core study of both production zones revealed no significant differences in permeability and porosity. On the other hand, an X-ray study of core samples showed differences in their structure and the presence of microporosity in the Bashkirian stage. The effectiveness of four different types of surfactants and surfactant blends were evaluated for both production zones by two different oil displacement mechanisms: spontaneous imbibition and filtration experiments. Results showed the higher effect of surfactants on wettability alteration and imbibition mechanisms for the Bashkirian cores with microporosity and a higher oil displacement factor in the flooding experiments for the Vereian homogeneous cores with lower oil viscosity.

Investigation of the efficiency of restrained oil displacement using of enhancing oil recovery methods

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Displacement of oil by SiO2-nanofluid from a microporous medium: microfluidic experiments

In this work, the process of displacing oil from a microfluidic chip that simulates a porous medium is studied. Experimental photographs of the process of oil displacement by water and SiO2-nanofluid are presented. It is shown that the use of nanofluid increases the oil displacement efficiency by 16%.

Improving Oil Recovery of the Heterogeneous Low Permeability Reservoirs by Combination of Polymer Hydrolysis Polyacrylamide and Two Highly Biosurfactant-Producing Bacteria

Polymer hydrolysis polyacrylamide and microbes have been used to enhance oil recovery in many oil reservoirs. However, the application of this two-method combination was less investigated, especially in low permeability reservoirs. In this work, two bacteria, a rhamnolipid-producing Pseudomonas aeruginosa 8D and a lipopeptide-producing Bacillus subtilis S4, were used together with hydrolysis poly-acrylamide in a low permeability heterogeneous core physical model. The results showed that when the two bacterial fermentation liquids were used at a ratio by volumeof 1:3 (v:v), the mixture showed the optimal physicochemical properties for oil-displacement. In addition, the mixture was stable under the conditions of various temperature (20–70 °C) and salinity (0–22%). When the polymer and bacteria were mixed together, it had no significant effects in the viscosity of polymer hydrolysis polyacrylamide and the viability of bacteria. The core oil-displacement test displayed that polymer hydrolysis polyacrylamide addition followed by the bacterial mixture injection could significantly enhance oil recovery. The recovery rate was increased by 15.01% and 10.03%, respectively, compared with the sole polymer hydrolysis polyacrylamide flooding and microbial flooding. Taken together, these results suggest that the strategy of polymer hydrolysis poly-acrylamide addition followed by microbial flooding is beneficial for improving oil recovery in heterogeneous low permeability reservoirs.

Study on the Oil Displacement Effect and Application of Soft Microgel Flooding Technology

Due to the reservoir heterogeneity, there is still a lot of remaining oil that cannot be displaced by water flooding. Therefore, taking the whole injection-production flow field as the research object, the dominant channel is divided into macro and micro channel. Then the corresponding oil displacement system is adopted to realize the continuous flow diversion and effective expansion of swept volume. For micro channels, the soft microgel particle dispersion can be used. It is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, the oil recovery rate can be greatly improved. Soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, its unique phenomenon of particle phase separation appears, which leads to the properties of "plugging large pore and leave the small one open", and the deformation and migration characteristic in the poros media. Therefore, particle phase separation of soft microgel particle dispersion is studied by using the microfluidic technology and numerical simulation. On this basis, by adopting the NMR and 3D Printing technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application cases are analyzed. Results show that, soft microgel particles have good performance and transport ability in porous media. According to the core displacement experiment, this paper presents the matching coefficient between microgels and pore throat under effective plugging modes. Also, the particle phase separation happens when injecting microgels into the core, which makes the particles enter the large pore in the high permeability layer and fluid enters into small pore. Therefore, working in cooperation, this causes no damage to the low permeability layer. On this basis, theoretically guided by biofluid mechanics, the mathematical model of soft microgel particle is established to simulate its concentration distribution, which obtained the quantitative research results. Furthermore, the micro displacement experiment shows that, microgels has unique deformation and migration characteristic in the poros media, which can greatly expand swept volume. The macro displacement experiment shows that, microgels have good oil displacement performance. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields since 2007. Results show that these field trials all obtain great oil increasing effect, with the input-output ratio range of 2.33-14.37. And two field application examples are further introduced. Through interdisciplinary innovative research methods, the oil displacement effect and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results play an important role in promoting the application of this technology.

SmartWater Synergy with Microsphere Injection for Permeable Carbonates

This paper presents a laboratory study on combination of SmartWater with microsphere injection to improve oil production in carbonates, which increases the sweep efficiency and oil displacement efficiency. In this study, the properties of a micro-sized polymeric microsphere were investigated including size distribution, rheology, and zeta potential in SmartWater, compared with conventional high salinity injection water. Coreflooding tests using natural permeable carbonate cores were performed to evaluate flow performance and oil production potential at 95°C and 3,100 psi pore pressure. The flow performance was evaluated by the injection of 1 pore volume microspheres, followed by excessive water injection. Oil displacement tests were also performed by injecting 1 pore volume of microspheres dissolved in SmartWater after conventional waterflooding. The median particle size of the microsphere in conventional injection water with a salinity of 57,670 ppm was about 0.25 µm. The particle size was increased by 50% to 100% with reduced elastic modulus when the microsphere dispersed in SmartWater with lower salinity. The zeta potential value of microsphere was decreased in SmartWater compared to that in conventional injection water, showing more negatively charge property. Flow performance of microsphere solutions in the carbonate cores was found to be dependent on their particle size, strength, and suspension stability. The results from coreflooding tests showed that the microsphere dispersed in SmartWater would result in higher differential pressure than that observed in conventional injection water. The SmartWater caused the microspheres swell to larger but softer particles with better suspension stability, which enhanced both the migration and blocking efficiency of microsphere injection. The oil displacement tests confirmed that the microsphere in SmartWater displaced more oil than that obtained with conventional injection water. This result was clearly supported by the higher differential pressure from microsphere injection in SmartWater. The oil bank appeared historically in the post water injection stage, which was quite different from the reported findings of typical mobility controlling agents in the existing knowledge. The microspheres were observed in the core flood produced fluids, indicating the improvement of microsphere migration by SmartWater. This work, for the first time, demonstrated that the combination of SmartWater and microsphere injection yields additional oil production. The proposed hybrid technique can provide a cost-effective way to improve waterflooding performance in heterogeneous carbonates.

CO2 Waterless Fracturing and Huff and Puff in Tight Oil Reservoir

CO2 fracturing technique is a kind of ideal waterless stimulation tech. It has the advantages of water free, low reservoir damage, and production increase by improving the reservoir pressure. At the same time, combined with reasonable shut-in control after fracturing, it can be realized integrated development technology of energy storage -fracturing and oil displacement with CO2 waterless stimulation. For low-grade and low-permeability tight reservoirs, through the integration technology of CO2 fracturing and CO2 flooding, fracture-type "artificial permeability" is formed in the formation, and micro-nano pore throat of underground matrix is formed as oil and gas production system, which realizes the development of artificial energy, reduces carbon emissions, effectively improves the productivity of low-permeability and tight reservoirs, thus further improves oil recovery. The technology mainly includes two aspects: vertical wells adopt CO2 fracturing + huff and puff displacement integration technology, horizontal wells adopt water-based fracturing + CO2 displacement technology, and utilize the high efficiency of CO2 penetration in reservoirs and crude oil viscosity reduction, which can greatly improve oil recovery, while achieving large-scale CO2 storage and reducing carbon emissions. It is both realistic and economic, and has great social benefits. The integrated development technology of energy storage -fracturing and oil displacement with CO2 waterless stimulation has been applied for 10 wells in oilfield, which has achieved good results in increasing reservoir volume, increasing formation energy, reducing oil viscosity and enhancing post-pressure recovery. As a result, the production of them has increased by over 100%. With low viscosity and high diffusion coefficient, supercritical CO2 is good for improving fracturing volume. Effective CO2 fracturing technology can improve stimulated reservoir volume, downhole monitoring results show that the cracks formed by CO2 fracturing is 3 times the size of those formed by water-based fracturing.

Three-Dimensional Visualization of Oil Displacement by Foam in Porous Media

Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.