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Abstract Universal existence of the filled vug or cave in carbonate reservoir complicates the fluid flow as the coexistence of free flow and porous flow. The fills in vug increase the flow resistance and affect the water invasion for a natural bottom-water reservoir. This influence was explored through experimental tests on a conceptual discrete fractured-vuggy model. This model was abstracted from Tahe Oilfield in China, in the form of isolated vugs connected by fractures network. A new scaling method was proposed for this discrete media according to the similarity of the displacement front of water drive. It was found that vug filling displays a negative role during the natural bottom-water drive. This impact depends on the geological feature of fractured-vuggy reservoir. A stronger sensitivity occurred to the fracture well-developed stratum that the vug filling made the pre-existing or new preferential corridors more significant. As a result, the systems with multiple flow paths became more "heterogeneous". In this condition, a lower water intensity and oil viscosity can ease these adverse effects. Highlights • Establish a new fractured-vuggy conceptual model in the form of isolated vugs connected by fractures network. • Establish a new scaling method for the discontinuous fracture-vug media based on the similarity of displacement front advance. • Conduct natural bottom-water drive in discrete fractured-vuggy model. • Show the effects of vug filling, bottom-water intensity, and fluid viscosity on oil displacement efficiency in this media. [ABSTRACT FROM AUTHOR]

Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically. [ABSTRACT FROM AUTHOR]

Poor sweep efficiency seriously limits field applications of CO 2 -EOR, especially in fractured reservoirs. The investigation of CO 2 production performance and the method to control CO 2 production becomes a key to successfully run a CO 2 -EOR project. In this study, artificial sandstone cores were used to perform a series of CO 2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO 2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO 2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO 2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO 2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO 2 within high permeability layer could successfully tune injected CO 2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO 2 production control, and also offered an optimal method to improve the conformance for CO 2 -EOR. [ABSTRACT FROM AUTHOR]

Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N 2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N 2 foam flooding. When the injection volume of N 2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N 2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Alkali plays an important role in alkali/surfactant/polymer (ASP) technology. The mechanisms of alkali were reviewed in this paper and the advantages were significant. In this study, three main steps were conducted. Firstly, ethanolamine was selected from four organic alkalies (ethanolamine, diethanolamine, triethanolamine and triethylamine) by interfacial tension (IFT) tests. Then the selected organic alkali, ethanolamine, was compared with inorganic alkali (sodium carbonate) by IFT performance. The results showed that ethanolamine had low IFT like inorganic alkali and it has lower IFT than sodium carbonate when concentration was higher than 0.8%. Secondly, alkali consumption experiment was conducted to compare organic alkali and inorganic alkali. The results indicated that ethanolamine had lower consumption than inorganic alkali, which maintained the efficiency of ASP flooding. Finally, the concentrations of silicon and aluminum in solution were measured to evaluate the reservoir damage caused by alkali. The results found that ethanolamine system had the lower concentrations of silicon and aluminum than inorganic alkali, which means it caused less reservoir damage. Thus, ethanolamine may be a potential alkali which can replace inorganic alkali in ASP technology. [ABSTRACT FROM AUTHOR]

Fractures and heterogeneity commonly exist in ultra-low permeability reservoirs, which will cause serious gas channeling phenomena and lead to poor oil recovery during CO 2 immiscible flooding. CO 2 water alternating gas (WAG) flooding combined with gas channeling control treatments are recognized as effective approaches to enlarge the sweep efficiency of CO 2 . Performance of gel systems were evaluated to screen out a high-strength gel which can be utilized as fracture blocking agent. Then, performance of small molecule amines were evaluated to screen out a kind of small molecule amine which can be utilized as rock-matrix blocking agent. Performance evaluation results showed that high-strength gel with 8% modified starch + acrylic amide, 0.05% crosslinking agent, 0.15% initiator and 0.15% stabilizer could be served as fracture blocking agent, while etheylenediamine was proposed as rock-matrix blocking agent which could react with CO 2 and generate solid particles to improve the heterogeneity of the reservoirs. To examine gas channeling control effect in actual reservoir conditions, a 3D radial flow model with complex fractures and heterogeneity was designed according to the actual oilfield, and five-spot pattern was employed in the model. Waterflooding, continuous CO 2 flooding, and gas channeling control using high-strength gel, etheylenediamine and CO 2 WAG flooding were conducted successively in the 3D radial flow model. After a series of treatments, the oil recovery was enhanced by 15.09%, which was significant for CO 2 immiscible flooding in the field application. The gas channeling along major fracture and microfractures of the model was effectively controlled by high-strength gel, while fluid diversion could occurred after ethylenediamine injection due to the solid particles which could mitigate gas channeling along relatively high permeability areas of the rock-matrix, and the gas channeling phenomena can be further mitigated by the mobility control ability of CO 2 WAG flooding. [ABSTRACT FROM AUTHOR]

The major objective of this paper was to evaluate the validity of in-situ CO 2 generation technique as an enhanced oil recovery method in sandstone reservoirs. In this study, the endothermic decomposition of ammonium bicarbonate solution was used to generate CO 2 . The theoretical prediction model of generated CO 2 volume under reservoir conditions was deduced from the reaction kinetics. It was verified by the experimental data from gas-forming reaction test. The results indicated that the prediction based on the established theoretical model was well matched to experimental results at the tested NH 4 HCO 3 concentrations of 10, 15, 20 wt%. The oil displacement efficiency of in-situ CO 2 generation huff-n-puff (ISCGHP) were further examined through both sandpack test and reservoir simulation. The gas-forming agent was composed of ammonium bicarbonate, surfactants and polymers. The displacement performance of ISCGHP was examined through the sandpack huff-n-puff test. Effects of the main injection parameters were analyzed, including concentration, slug size, injection mode and chasing water. The sandpack huff-n-puff test indicated that a higher concentration of NH 4 HCO 3 and a larger slug size of reagent contributed to an improved oil displacement efficiency. Gradually increasing the slug size reached the remaining oil left in the previous cycle, and simultaneously enlarged swept volume in the following cycle. In the numerical study, the reservoir model of ISCGHP was established using data from interfacial tension test, PVT test and reaction kinetics. It was then calibrated based on sandpack test results and past production observations of the candidate-well. Results showed ISCGHP effectively improved single-well productivity with a growth rate of 56% in oil production, the effective sweep radius reached about 50 m away from the wellbore along with a slight fall of formation temperature and a maximal 22.8% of oil viscosity reduction. [ABSTRACT FROM AUTHOR]

The 4th block Ordovician fractured-cavity carbonate reservoir of Tahe oil-field consists of high-density fractures and large caves which are well developed. The oil is stored in fractures and caves, rather than carbonate rock matrix. In other words, the carbonate rock matrix has no oil storage capability and permeability is extremely low. The fractured-cavity carbonate reservoir possesses the features of severe heterogeneity, complex structure of reservoir space. During the development, many shortcomings such as short period of stable production, early water breakthrough, fast increasing of water cut, high natural decline rate and low degree of development are exposed gradually. The well which cannot achieve effectiveness by water injection was selected to carry out N 2 flooding experiments in Tahe oil-field. By the end of September 2012, the total injection volume of high pressure N 2 was 700 m 3 and the incremental oil production was 2600 t. However the displacement mechanism was still poorly understood. In this paper, a two-dimensional visual fractured-cavity carbonate reservoir model was developed based on the distribution feature, space structure and connection type of fractures and caves in reservoir space. Four main types of residual oil i.e., attic oil, locked oil, bypassed oil and residual oil trapped in the filled area were determined from the water flooding experiments. Also, their formation mechanism was investigated. In addition, the recovering mechanism of residual oil was clarified on the basis of N 2 flooding experiments. The results show that N 2 flooding can significantly increase the oil recovery by more than 40% after water flooding, and it mainly mobilized attic oil and partial locked oil. The entire experiment process was recorded by video, therefore the displacing process of residual oil can be observed directly. These results in this study indicate that N 2 flooding has a broad application prospect in fractured-cavity carbonate reservoir. [ABSTRACT FROM AUTHOR]

The objective of this paper is to investigate an oil-tolerant foam system as a displacing agent to improve the efficiency of oil recovery. To achieve this objective, several foaming agents are examined based on foam–oil interaction models and previous studies. By measuring the interfacial and surface tensions of surfactants, we investigate the implications of the value of spreading coefficient and the lamella number in a system of foaming agents. The foamability and foam stability of the preferred foaming agents were statically tested. At last, the oil tolerance of the foaming agent system in both static and core flow experiments was investigated. Results indicated that the oil tolerant foaming system performs best among the various surfactants tested. In static testing, both foamability and foam stability increase as concentrations of surfactant and salt increase. It was also observed that the polymer significantly increases the foam stability in the presence of oil. The oil droplets do not spread at the surface due to the properties of the oil-tolerant foam, so the foam can be stable in the presence of crude oil. The oil tolerant foaming system exhibits much greater foaming volume and longer drainage-half time than ordinary foam, either in the presence or absence of oil. The mobility reduction factor for dynamic displacement of oil-tolerant foam is much higher than those of pure foam and polymer solutions in the presence of oil. Experiments with different remaining oil saturations reveal that when the residual oil saturation is about 40%, the oil-tolerant foam can achieve the highest oil recovery. [ABSTRACT FROM AUTHOR]

Abstract: Studies have been done in order to treat alkali scale related problems encountered in the alkali/surfactant/polymer (ASP) flooding pilot area of Daqing Oilfield. The interfacial tensions (IFT) of ASP solutions are tested using TX-500 type interfacial tensimeter (made in the USA). The effect of alkalis and surfactants on the viscoelasticity of ASP solutions are studied using HAAK RS-150H type rheometer (made in Germany). Macro-coreflood tests are performed using natural cores, 2-D vertically-heterogeneous artificial cores without restraining barriers, and 2-D vertically-heterogeneous artificial cores with restraining barriers. Blind ends'' residual oil sweeping tests are performed with simplified blind-end models. The studies indicate that alkali has adverse effect on the viscoelasticity of an ASP solution. A high concentration of alkali can cause the HPAM molecular chains curl up, and can form alkali scales, although it is beneficial to an ultralow IFT. Ultralow IFT has a pronounced effect on the oil recovery of a homogeneous reservoir, while the viscoelasticity of an ASP solution contributes more to the oil recovery of a heterogeneous reservoir. The stronger the homogeneity is, the greater the effect of IFT on the oil recovery; on the contrary, the stronger the heterogeneity is, the greater the effect of viscoelasticity on the oil recovery. Laboratory “co-injection and separated-layer production” experiment also shows that a reasonable (for example 0.6%) rather than too high an alkali concentration is more beneficial to starting-up layers with medium and low permeability, and washing out the residual oil in the swept layers, and a relatively high viscoelasticity is more beneficial to sweeping the residual oil in blind ends. As far as a heterogeneous reservoir is concerned, ultralow IFT is not a ‘have-to” condition for enhancing oil recovery, while the viscoelasticity of an ASP solution is more important to effectively sweeping oil. The capillary number theory is of great practical importance for homogeneous reservoirs, but it has limitations and cannot be readily applied in heterogeneous reservoirs. For example, the trend of capillary numbers versus IFTs (corresponding to different alkali concentrations), which are based on the theory, does not match with the trend of oil recovery efficiencies. Therefore, for a heterogeneous reservoir, without an ultralow IFT (for example with an IFT of 10−2 mN/m), i.e. with a reasonably lower alkali concentration, a satisfying oil recovery can still be achieved as long as the viscoelasticity is high enough. This not only can solve the problems caused by alkali scales, but also can enlarge the selecting range of surfactants and reduce the cost of ASP flooding. [Copyright &y& Elsevier]

Fault-karst fractured-vuggy carbonate reservoir is an important type of fractured-vuggy carbonate reservoirs in Tahe oilfield of China. The fluids flow behaviors in fault-karst fractured-vuggy carbonate reservoir are complex and unclear due to the complexity of the connection between fractures and vugs. In this work, the novel 2D visual fault-karst fractured-vuggy carbonate reservoir physical models (longitudinal model and horizontal model) were designed and fabricated to investigate the flow characteristics and phase behaviors of nitrogen gas and foam-assisted nitrogen gas floods. Experimental results showed that oil-water and gas-oil interfaces fluctuations had positive effect on improving oil recovery. Foam-assisted nitrogen gas can effectively inhibit the occurrence of gas channeling, improve swept volume and increase oil recovery. A four-phase dimensionless index (Nr') was first proposed to describe the synergistic effects among the gas cap, foam cap and bottom water during foam-assisted nitrogen flooding process. Based on the analysis of oil recovery results, there was a turning point on oil recovery curve for foam-assisted nitrogen gas flooding. Moreover, the optimal production mode that was injection in high position of reservoir and recovery from low position of reservoir (HI-LR) in fault-karst carbonate reservoir was determined. This study is helpful to understand the flow characteristics of foam and nitrogen gas and provides a guide for increasing oil recovery in fault-karst fractured-vuggy carbonate reservoirs. • The novel 2D visual fault-karst fractured-vuggy carbonate reservoir physical models were designed and fabricated to investigate the flow characteristics and phase behaviors of nitrogen gas and foam-assisted nitrogen gas floods. • Foam-assisted nitrogen gas could effectively inhibit the occurrence of gas channeling, improve swept volume and increase oil recovery. • A four-phase dimensionless index (Nr') was proposed to describe the synergistic effects among the gas cap, foam cap and bottom water during oil recovery near the production well pores. • The optimal production mode of injection in high position of reservoir and recovery from low position of reservoir (HI-LR) in fault-karst carbonate reservoir was determined. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoir played a significant role in unconventional reservoirs, but it was difficult to be developed due to its complex reservoir types. Therefore, it was crucial to find a suitable development program to enhance oil recovery. In this work, a two-dimensional visual physical model of fractured-vuggy reservoir was designed and fabricated according to actual geological data and injection-production characteristics of a representative fractured-vuggy carbonate reservoir, Tahe Oilfield in China. Nitrogen flooding experiment, nitrogen flooding under the high gas energy experiment, nitrogen flooding under strong bottom water energy experiment and foam assisted nitrogen gas flooding experiment were carried out respectively by using two-dimensional visual model. The flow behaviors and the main mechanisms for enhanced oil recovery were revealed by analyzing the oil displacement performance in the visual physical model. Experiment results showed that the gas cap energy and the bottom water energy played a synergistic effect in the nitrogen flooding. The stronger the bottom water energy was, the larger the gas spread area was, and the increase of oil recovery would be very high. If the gas injection rate was too strong, the dominant gas flow channel would be formed prematurely, and the oil recovery was little increase. In addition, foam could effectively control the gas mobility, delay the formation of gas channeling. Meanwhile, the oil recovery of foam assisted nitrogen gas flooding was higher 12% than that of nitrogen flooding. Therefore, the mechanism for improving the degree of development was obtained mainly through gravity differentiation to form the secondary gas top and realize the development of the remaining oil. • A two-dimensional visual physical model of fractured-vuggy reservoir was designed and fabricated. • The flow behaviors and the main mechanisms for nitrogen and foam assisted nitrogen gas flooding were studied. • The oil recovery of foam assisted nitrogen gas flooding was higher 12% than that of nitrogen flooding. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoirs are becoming the key to oil reserves, but their complex reservoir structure and connectivity make it difficult to be developed. In this work, a visual physical model representing an underground river reservoir in two-dimensional fractured-vuggy reservoir was designed and fabricated to study gas channeling characteristics of nitrogen and foam flooding. In order to further study the influence of the porous media on gas channeling characteristics of foam and nitrogen gas flooding, the visual physical model was filled with 2 mm transparent glass beads and the effects of glass beads on different types of nitrogen and foam flooding gas channeling were studied. Experimental results showed that the synergistic action of gas and water and the bottom water energy were the important factors affected gas channeling. Furthermore, foam could effectively control gas mobility, delay formation of gas channeling. In terms of enhanced oil recovery, the recovery efficiency of foam flooding was 35% higher than nitrogen flooding in the horizontal model. In addition, the glass beads in fractured-vuggy of underground river reservoirs could change the flow direction of the fluid and cause a certain flow resistance, foam was more easily to occur gas channeling in the longitudinal model filled with glass beads. The oil recovery by foam in the longitudinal model filled with glass beads was lower 12% than that in the longitudinal model. Therefore, determined the factors that influence gas channeling had a practical value for enhancing oil recovery in fractured-vuggy reservoirs. • Designed and fabricated two-dimensional visual physical model of fracture-vuggy reservoir. • The main control factors affected gas channeling were determined. • Foam could effectively control gas mobility, delay formation time of gas channeling and improve oil recovery. [ABSTRACT FROM AUTHOR]

Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using α-starch, acrylamide, N,N′-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T 90 as indicators at temperature of 30–120 °C, salinity of 0–240 g/L and oil percentage of 0–50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery. [ABSTRACT FROM AUTHOR]

Tahe Oilfield, located in Tarim Basin, Northwest China, is a typical carbonate fracture-vuggy reservoir. Nitrogen gas flooding is a vital technology for improving oil recovery by enlarging sweep volume in fracture-vuggy reservoirs. However, gas channeling restricts further application of nitrogen gas flooding. This paper studied the characteristics of gas channeling in fracture-vuggy carbonate reservoirs using physical simulation. Visual physical models and macroscopic physical models were designed and fabricated based on similarity criterion. Nitrogen gas flooding experiments were conducted in both types of models. Experimental results demonstrated that once the dominant channel of gas is formed, the remaining oil cannot be effectively swept. The greater the areal heterogeneity of fracture-vuggy carbonate reservoir is, the easier the formation of gas channeling is. Gas channeling was accompanied by a large amount of oil and water production. The initial gas channeling was followed by several additional occurrences of gas channeling. In addition, PIR risk assessment method was proposed to predict gas channeling by assigning values to each coefficient of P, I and R. This method verified by oilfield data can be used to prevent and evaluate the risk of gas channeling in fracture-vuggy carbonate reservoirs. Image 1 • Designed and fabricated visual physical models and macroscopic physical models of fracture-vuggy carbonate reservoirs. • Gas channeling could lead to pressure fluctuation, large liquid production and several times of gas channeling after it. • The "PIR" risk assessment method of gas channeling was proposed for three typical fracture-vuggy carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Nitrogen gas drive and foam drive are commonly adopted for practical production in fractured carbonate reservoirs. A systematic study on nitrogen gas drive and foam assisted nitrogen gas drive in varying-aperture fractures is a practical and essential method to understand the EOR mechanism. In this study, we designed and fabricated similarity models and microscopic visual models. The fluid flow mechanisms were discussed combining the pressure response and dynamic displacement phenomenon. Experimental results show that the effective time of nitrogen gas drive was longer in decreasing-aperture fractures than that in increasing-aperture fractures. After water flooding, 0.8 PV nitrogen gas injection lead to gas channeling in decreasing-aperture fracture of 1 mm–0.2 mm while 0.6 PV nitrogen gas injection by reverse displacement direction. Both production rate and average pressure appeared discrete in narrow fracture compared to wide fracture. Enhanced oil recovery efficiency by foam drive was average 5% higher than that by nitrogen gas drive in single fracture. The displacement front of foam varies in four forms: micro-scale foam accumulation, small-scale foam accumulation, mesoscale foam slight deformation and large-scale foam serious deformation. This study could provide a theoretical basis for enhance oil recovery and further dig the potential of remaining oil in fractured carbonate reservoirs. • Designed and Fabricated similarity models and microscopic visual models of varying-aperture fractures of carbonate reservoirs. • There is a synergistic effect of gas and water flooding in fractures, which promote to oil production by regulating the position of oil-water interface in fractures. • The displacement front of foam varies in four forms: micro-scale foam accumulation, small-scale foam accumulation, mesoscale foam slight deformation and large-scale foam serious deformation. [ABSTRACT FROM AUTHOR]

The technical feasibility of using organic alkali instead of an inorganic one during alkaline/surfactant/polymer (ASP) flooding in a heterogeneous reservoir under a high temperature of 95 °C in China was investigated. Laboratory experiments were performed to evaluate the alkali consumption, adsorption, and retention in formation and its formation damage. Also viscosity of the ASP compound flooding system, oil/water interfacial tension, and chromatographic separation were investigated. A comparison of results obtained through organic alkali with those obtained from inorganic alkali was conducted to evaluate the flooding effect of this system, and the mechanism of increasing recovery ratio was analyzed. Experimental results indicated that the consumption and dynamic adsorption of ethanolamine and formation damage observed through the organic alkali were significantly lower than those observed through the inorganic alkali. When compounded with the surfactant, ethanolamine could further decrease the oil/water interfacial tension. Moreover, ethanolamine exerted a protective effect on the surfactant, thereby decreasing adsorption loss. A flooding experiment with a 5-spot pattern was performed on a heterogeneous reservoir. Findings revealed that the organic ASP (OASP) compound flooding system achieves good displacement effects and mobility control even under high temperature conditions and significantly improved recovery ratios. As such, the proposed method is feasible for compound flooding in high-temperature reservoirs. The mechanism of OASP compound flooding was discussed to provide a theoretical basis for optimizing compound flooding systems for high-temperature heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

Reservoir heterogeneity and natural fractures greatly affect CO 2 flooding efficiency in ultra-low permeability oil reservoirs. CO 2 water alternating gas (WAG) flooding and the combinations of continuous CO 2 flooding and gas channeling treatments are recognized as effective approaches to improve CO 2 sweep efficiency. It is of major interest to propose the novel gas channeling treatments and conduct a feasibility study of different CO 2 -EOR technologies. Heterogeneous cores with different permeability ratios and fracture model were utilized in the laboratory experiments to simulate different types of heterogeneity in the oil reservoirs. Continuous CO 2 flooding, CO 2 WAG flooding, continuous CO 2 flooding+one-stage gas channeling control, and continuous CO 2 flooding+two-stage gas channeling control were conducted after water flooding in homogeneous and heterogeneous cores and fracture model. Ethylenediamine and modified starch gel were proposed as blocking agents to mitigate gas channeling. During the experiments, the CO 2 flooding efficiency was evaluated through the oil recovery increment, fluid mobility control and the changes of producing pressure drop. Experimental results show that producing pressure drop during continuous CO 2 flooding decreases rapidly with an increase in permeability ratio. Continuous CO 2 flooding cannot displace much of remaining oil in low permeability layers due to high mobility of CO 2 and serious heterogeneity. WAG flooding can effectively control the fluid mobility and improve CO 2 flooding efficiency when the permeability ratio is less or equal to 30. Plenty of remaining oil can be displaced by combining continuous CO 2 flooding and gas channeling treatments. When the permeability ratio is less or equal to 100, ammonium carbamate, the reaction product of injected ethylenediamine and CO 2 can block off high permeability layer and impel the injecting gas into low permeability layer. The two-stage injection of modified starch gel and etheylenediamine can significantly mitigate the gas channeling within high-capacity gas channel model and fracture model during continuous CO 2 flooding, and the incremental oil recovery could be more than 20%. Pilot test of CO 2 flooding was operated in Northwest China and concentrations of CO 2 are monitored in six production wells. Two kinds of construction plans for gas channeling treatments have been preliminary designed to control the gas channeling in the pilot. [ABSTRACT FROM AUTHOR]

Multi-thermal fluid is a new heat-carrier proposed in decades. This paper introduces multi-thermal fluid into the thermal recovery process of thick heavy oil reservoir (THOR). First, using the method of physical simulation, the superiority of multi-thermal fluid is investigated from the Pressure–Volume–Temperature (PVT) performance and displacing characteristics. Thereafter, based on multi-thermal fluid injection technology and steam-assisted-gravity-drainage (SAGD) theory, a new Improved-Oil-Recovery technique for THORs, Multi-thermal Fluid Assisted Gravity Drainage (MFAGD) technique is proposed in this paper. Applying the dimensionless scaling criterion of gravity-drainage process, two 3D gravity-drainage experiments (SAGD, SAGD-to-MFAGD) are conducted. Thus, the enhanced-oil-recovery (EOR) mechanisms of multi-thermal fluid in heavy oil reservoirs are analyzed, and the thermal recovery performance of MFAGD process is discussed. Results indicate that compared with SAGD process, MFAGD process has a higher recovery rate, and it could further improve the gravity-drainage effect in THOR. Besides the conventional operation of SAGD, the EOR mechanisms of MFAGD technique also include heat insulation, energy recovery, gas dissolution and auxiliary cleanup of non-condensable gas. This method technologically supports the effective and efficient development of THORs. [ABSTRACT FROM AUTHOR]

Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide owing to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. Here, the amphiphilic molybdenum disulfide nanosheets were synthesized through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of defects on the MoS 2 nanosheets surfaces. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS 2 nanosheets) are approximate 67 nm in width. The effects of ultralow concentration ODA-MoS 2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the laboratory displacement experiments were also carried out to reveal the adsorption rules and the oil displacement effects by using ultralow concentration ODA-MoS 2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 h after 50 mg/L ODA-MoS 2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 μm can be formed after the addition of ODA-MoS 2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS 2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS 2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS 2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% (OOIP) is achieved. Finally, the production performance of ultralow concentration of ODA-MoS 2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed. • A straightforward hydrothermal method is used to synthesize amphiphilic molybdenum disulfide nanosheets. • Amphiphilic MoS 2 can change the oil-wet solid surface into a neutral-wet solid surface and form micro-scale emulsions. • Core flooding experiments show excellent abilities in oil displacement efficiency (average 16.26%). • The applications of amphiphilic MoS 2 in Daqing oilfield have achieved excellent effects on oil production increase. [ABSTRACT FROM AUTHOR]

CO 2 flooding is a promising technology used to enhance oil recovery as it increases oil production and sequesters CO 2 in low permeability oil reservoirs. However, the areal heterogeneity of a reservoir can seriously affect CO 2 flooding efficiency. The importance of production control treatments (sweeping area regulation, differential production pressure control, and real-time producing regulation) are thus proposed to improve the performance of CO 2 flooding in areal heterogeneous reservoirs. Three dimensional (3D) physical models and core-scale numerical models with areal heterogeneity and 5-spot patterns are designed using dimensionless scaling groups. Conventional CO 2 flooding and CO 2 production control flooding are conducted successively in the 3D models, and flooding efficiency is evaluated through oil recovery increments and changes in the displacement pressure drop curves. Mechanisms of CO 2 performance improvement using production control treatments are also discussed through the analytical analysis of gas distribution and gas/oil mobility ratio. 3D experimental and numerical simulation results show that CO 2 is displaced unevenly in the areal heterogeneous reservoir, leaving plenty of oil in the area of relatively low permeability. However, oil recovery of CO 2 flooding in the areal heterogeneous reservoir can be doubled using production control treatments (sweeping area regulation, differential pressure control, or real-time producing regulation). The oil remaining in the area of relatively low permeability can be effectively displaced using sweeping area regulation, and both a larger sweeping area and a better CO 2 flooding profile can be obtained using differential pressure control and real-time producing regulation. Through the analytical analysis of gas distribution and gas/oil mobility ratio, it is found that gas/oil mobility ratio is more sensitive to the areal heterogeneity, and real-time producing regulation has a powerful mobility control ability for CO 2 -EOR. Improvements in the performance of CO 2 flooding using production control treatments provide a feasible technical strategy to treat with the areal heterogeneity and enhance the oil recovery for 5-spot well patterns in the areal heterogeneous reservoir. [ABSTRACT FROM AUTHOR]

A new-type plugging coated particle system was investigated which is applied in high temperature & salinity reservoir, the temperature up to 300 ℃ and salinity up to 250,000 mg/L. To analyze these factors, based on adhesion feature of the particle, a series of experiments were performed to investigate properties of particle and its suspension system, including dynamic plugging experiments, etc. The results showed that the particles can adhere together under certain temperature up to 140 ℃. Moreover, the particle suspension, including HPG system and foam system, were screened based on suspending time. In addition, we selected four parameters, including salinity, injection rate, permeability and mass fraction, to measure plugging ability of system. Meanwhile, the visual microscopic models and glass sand-pack models were designed to observe directly particle flow in the porous media. Finally, the force analysis of particles at some special locations in the models was simulated by COMSOL Multiphysics. Experimental results confirmed the essential characters of new-type particle and indicate that this plugging system had excellent plugging performance in high temperature & salinity environment. The particle migration had strong correlation with permeability and the particle had impacted on the original structure of mineral. The process of packing was accelerated and repeated. Besides, keeping the particle single and improving material strength would promote plugging effects. The evaluation and mechanism research of new type plugging particle could provide guidance for plugging agent selection in high temperature and field development project designing. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition has been proved to be a promising enhanced oil recovery method for tight reservoirs, but the mechanisms of spontaneous imbibition oil recovery (SIOR) are still unclear. Here, we use the self-prepared novel lower-phase nano-emulsion (LWPNE) to reveal the mechanisms. In LWPNE solution, nano-scale oil drops (NODPs) in 6 nm diameter are formed and dispersed with co-presence of micelle solubilizing N-hexane. The effects of LWPNE on both interfacial tension (IFT) and contact angle were studied at 0–10,000 mg/L salinity condition, and spontaneous imbibition efficiency was determined from imbibition experiments in Amott cells at 60 °C. Electron Microscope and Transmission Electron Microscope were used to analyze the emulsification and solubilization mechanisms of LWPNE. Experimental results show that the original 135° (oil-wet) contact angle can be reduced to 32.7° (water-wet); the IFT is decreased to 0.0038 mN/m, and electrolyte has no contribution to either IFT reduction or wettability alteration. The average oil recovery from spontaneous imbibition testing using 0.3 wt% LWPNE is 44.1%, which is 20.5% higher than that from systems at similar conditions but using brine only. The LWPNE can solubilize oil by increasing NODPs' sizes to average 36 nm in diameter, which is the dominant mechanism to improve SIOR for LWPNE. The solubility of LWPNE is evaluated by the diameter growth rate of NODPs, and once it reaches 350%, a self-driving force drives oil drops to move forward. Moreover, the transformation mechanisms of spontaneous imbibition modes from imbibition to drainage are revealed by using the imbibition discriminant parameter (N B m − 1 ). • The nano-scale oil drops (NODPs) with a size of 6 nm in diameter are formed and evenly dispersed with co-presence of micelle solubilizing N-hexane. • The emulsification and solubilization effects of NODPs are discovered to be the dominant mechanisms for spontaneous imbibition oil recovery (SIOR). • A self-driving force (pressure difference at the curved interface) is proposed to drive oil drops moving forward during the solubilization processes. [ABSTRACT FROM AUTHOR]

Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 °C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C 16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C 12 surfactants), which was mainly depending on better IFT reduction ability of C 16 surfactants than C 12 surfactants. Appropriate IFT reduction, such as 10−1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10−2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs. • The spontaneous imbibition efficiencies of different surfactant solutions based on molecular structures were investigated systematically. • The reasons for the imbibition efficiency differences of different solutions were investigated in detail. • The optimum surfactant types and IFTs suitable for imbibition were obtained. [ABSTRACT FROM AUTHOR]