Hot Water Flooding Research Articles

A prediction method of oil recovery for hot water chemical flooding in heavy oil reservoirs: Semi-analytical stream tube model

Abstract Chemical agents (polymer and surfactant) assisted hot water flooding is an effective means of enhancing oil recovery in heterogeneous and heavy oil reservoirs. The rapid prediction of oil recovery through hot water chemical flooding is very important. The stream tube model is a fast analytical method for predicting water flooding recovery, but it is not suitable for hot water chemical flooding. In this paper, a permeability distribution model for multi-stream tubes is established based on permeability variation coefficient using normal distribution function for reservoir heterogeneity, Using GOMPERTZ growth function model to characterize the changes in stream tube temperature, polymer viscosity, and surfactant concentration with injection volume, Using Brooks-Corey model to describe the influence of interfacial tension and temperature on the relative permeability curve. Finally, an analytical stream tube model for hot water chemical flooding of heavy oil reservoirs was established. The time discrete method is used to solve the model, then the graphs of the relationship between oil recovery and water cut are obtained. Compared with numerical simulation methods, the prediction error of oil recovery is less than 2%, and the calculation time is reduced by 89%. This model has been successfully applied to X oilfield. Based on historical fitting, it is predicted that hot water chemical flooding can enhance oil recovery by 6.3% compared to water flooding. This paper provides a fast calculation method for predicting and evaluating the effectiveness of hot water chemical flooding in heavy oil reservoirs.

Importance of Clay Swelling on the Efficacy of Cyclic Steam Stimulation in the East Moldabek Formation in Kazakhstan

Both steam and hot water flooding of high-viscosity oils in the presence of swelling clays are difficult methods for producing oil efficiently because of potential formation permeability reduction. This paper pertains to heavy oil recovery from the East Moldabek formation where the oil API gravity is about 22 and is inundated with swelling clays. To achieve this, we used the IntersectTM reservoir simulator to compare oil recovery economics using both hot water and steam injection as a function of steam cycle duration, temperature, and steam dryness. We also studied clay swelling in the East Moldabek formation where clay poses a significant challenge due to its impact on permeability reduction. In this research, we developed an equation based on experimental data to establish a relationship between water mineralization and permeability in the East Moldabek formation. The equation provides valuable insight on how to mitigate clay swelling which is crucial for enhancing oil recovery efficiency—especially in sandstone reservoirs. Our modeling studies provide the recovery efficiencies for salinities of the hot water EOR versus cyclic steam EOR methods in a formation containing swelling clays. Specifically, the reduction in formation permeability as a function of the distilled water fraction is the controlling parameter in hot water or steam flooding—when the formation water mixture becomes less saline, oil recovery decreases. Our research shows that clay swelling can significantly impact cyclic steam stimulation outcomes, potentially reducing its effectiveness, while hot water flooding may offer a more cost-effective and operationally feasible solution in formations where clay swelling is a concern. Economic analysis reveals the potential for achieving an optimal favorable condition for hot water injection. Therefore, this paper provides a guideline on how to conduct thermal oil recovery for heavy oils in fields with high clay content such as the East Moldabek deposit.

Study on the pathways of thermochemical sulfate reduction between sulfates and alkanes at low temperatures

To reduce the energy consumption of heavy oil thermal recovery, low-temperature hot water flooding is becoming popular. The occurrence of thermochemical sulfate reduction (TSR) reactions during the hot water flooding process generates H2S, which can corrode equipment and jeopardize personnel safety. Preventing and managing H2S requires studying TSR reactions. The study investigated the reactivity of SO42-, HSO4-, and [MgSO4]CIP in the TSR reaction during heavy oil low-temperature hot water flooding. The results indicated that during low-temperature hot water flooding, no significant thermal cracking of heavy oil occurs, only a minor aquathermolysis takes place, while the TSR reaction proceeds vigorously. The TSR reaction leads to increased yields of H2S, CH4, and CO2, as well as a higher S content in the heavy oil. Based on experimental results, numerical simulations of the reaction process between SO42- and CH4 were conducted using density functional theory and transition state theory. The results indicated that the reduction of SO42- to produce SO32- is the rate-limiting step in the entire reaction pathway between SO42- and CH4. Further analysis of the reaction barriers and chemical reaction rates of the three sulfates (SO42-, HSO4-, and [MgSO4]CIP) and C1-C5 alkanes was conducted based on the limiting step. Through macro and micro analysis, this study not only confirmed previous findings regarding the order of alkanes participating in TSR reactions from the perspective of microscopic molecular but also clarified the oxidation order of sulfate species under heavy oil low-temperature thermal water flooding conditions, with the sequence being HSO4- > [MgSO4]CIP>SO42-. This study provides a foundational understanding of TSR reactions during heavy oil low-temperature hot water flooding and is of significance for the prediction and management of H2S.

Influence of pore structure heterogeneity on channeling channels during hot water flooding in heavy oil reservoir based on CT scanning

Hot water flooding is an effective way to develop heavy oil reservoirs. However, local channeling channels may form, possibly leading to a low thermal utilization efficiency and high water cut in the reservoir. The pore structure heterogeneity is an important factor in forming these channels. This study proposes a method that mixes quartz sand with different particle sizes to prepare weakly heterogeneous and strongly heterogeneous models through which hot water flooding experiments are conducted. During the experiments, computer tomography (CT) scanning identifies the pore structure and micro remaining oil saturation distribution to analyze the influence of the pore structure heterogeneity on the channeling channels. The oil saturation reduction and average pore size are divided into three levels to quantitatively describe the relationship between the channeling channel distribution and pore structure heterogeneity. The zone where oil saturation reduction exceeds 20% is defined as a channeling channel. The scanning area is divided into 180 equally sized zones based on the CT scanning images, and three-dimensional (3D) distributions of the channeling channels are developed. Four micro remaining oil distribution patterns are proposed, and the morphology characteristics of micro remaining oil inside and outside the channeling channels are analyzed. The results show that hot water flooding is more balanced in the weakly heterogeneous model, and the oil saturation decreases by more than 20% in most zones without narrow channeling channels forming. In the strongly heterogeneous model, hot water flooding is unbalanced, and three narrow channeling channels of different lengths form. In the weakly heterogeneous model, the oil saturation reduction is greater in zones with larger pores. The distribution range of the average pore size is larger in the strongly heterogeneous model. The network remaining oil inside the channeling channels is less than outside the channeling channels, and the hot water converts the network remaining oil into cluster, film, and droplet remaining oil.

Development of Novel Star-Like Branched-Chain Acrylamide (AM)-Sodium Styrene Sulfonate (SSS) Copolymers for Heavy Oil Emulsion Viscosity Reduction and Its Potential Application in Enhanced Oil Recovery.

Injecting water with chemicals to generate emulsions in the reservoir is a promising method for enhancing heavy oil recovery because oil-in-water (O/W) emulsions significantly reduce oil viscosity. To enhance heavy oil recovery efficiency, we developed new star-like branched AM-SSS copolymers (SB-PAMs) with reduction in the viscosity of the heavy oil emulsion, which was synthesized by reversible addition-fragmentation chain transfer (RAFT) controlled radical polymerization. The core structure of the branched polymer was RAFT polymerization of acrylamide (AM) and N,N'-methylene bis-acrylamide (BisAM), in the presence of 3-(((benzylthio)carbonothioyl)thio)propanoic acid as a chain transfer agent, followed by chain extension with AM and SSS. The core structures were achieved by incorporation of total monomer ratios [BisAM]/[AM] of 1:11. The expansion of the core structures by copolymerization of AM and SSS resulted in star-like branched polymer SB-PAM-co-SSS with apparent molecular weights ranging from 240 to 2381 kDa. 1H-nuclear magnetic resonance (1H NMR) and Fourier transform infrared (FTIR) confirmed the synthesized polymer structure. The molecular weight was determined by gel permeation chromatography (GPC). The polydispersity coefficient was between 1 and 7, which has a broad molecular weight distribution. The polymer dissolves only 0.75 h in deionized water, faster than conventional polyacrylamide. At 50 °C, the viscosity of the 1000 mg/L SB-polymer solution can reach up to 45 mPa·s. First, heavy oil viscosity reduction by 800 mg/L SB polymer can reach 91.7%, at a water dehydration rate of 90.4%; second, with 0.6 PV injection, 800 mg/L SB polymer improved oil recovery up to 23.66% after water flooding; and third, SB-polymer-assisted hot water flooding shows that heavy oil recovery improved by 19.46% at 110 °C with 0.6 pore volume (PV) SB-polymer injection. This novel branched chain polymer with heavy oil emulsion capability will shed light on high-temperature polymer flooding and the development of a new candidate structure for heavy oil viscosity reduction.

Study on low-heat synergistic chemical profile control and flooding technology in Bohai Oilfield

Introduction: Through the combination of hot water and chemical agent, the low-heat synergistic chemical profile control and flooding technology can not only reduce the risks of sand production and string damage caused by high-temperature thermal recovery technology, but also further improve the recovery factor on the basis of hot water flooding.Methods: Based on laboratory testing, the synergism mechanism of thermal energy and chemical agent is studied.Results: The research results showed that in the near wellbore zone of the injection well, crude oil viscosity reduction mainly relies on thermal energy, and chemical agents assist in improving the water oil mobility ratio and reducing the risk of cross flow. After entering the deep formation, due to the decrease in temperature, the thermal energy effect is weakened, but the chemical agents still aggregate at the oil-water interface and continue to act on heavy oil to reduce viscosity. The higher the temperature, the greater the role of heat energy, and the weaker the role of chemical agents. The higher the injection concentration of chemical agent, the more obvious the leading role of chemistry. Based on the comprehensive evaluation index, the optimized temperature is 80°C and the injection concentration is 1500 mg/L. The scheme study of Bohai L Oilfield shows that compared with cold water flooding, hot water flooding can only improve oil recovery by 1.2 percentage points, and low heat collaborative chemical profile control flooding technology can further improve oil recovery by 4.7 percentage points on the basis of hot water flooding, with obvious oil increase effect.Conclusion: It is suggested that Bohai L Oilfield should apply low-heat coordinated chemical profile control and flooding technology to improve the development effect of the oilfield, and provide new technical ideas for safe and economic development of offshore heavy oil.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant

NUMERICAL INVESTIGATION ON THE IMPACT OF INITIAL WATER SATURATION DISTRIBUTION ON HOT WATER FLOODING PERFORMANCE UNDER NON-ISOTHERMAL CONDITIONS

The heterogeneity in the spatial distribution of initial water saturation influences the performance of hot water flooding. The prospect of a reduction in oil recovery arises from the development of viscous instability. In the present study, a numerical simulation model has been developed by coupling heat transport, and multiphase flow in porous media integrated with the non-isothermal flow, and the numerical model has been verified with the existing analytical solution by Buckley and Leverett. The formation of a wavy temperature profile at the condensation front was found with a decreased depth of temperature penetration. The average rise of temperature is drastically affected by the spatial distribution of initial water saturation. The formation of viscous fingering was highly dominating in the reservoir, with initial water saturation randomly distributed and causing the front to move in an irregular pattern from the initial stage of the flooding. The heterogeneous reservoir with initial water distribution showed the earlier formation of viscous fingering than the homogeneous reservoir. The heterogeneity in the spatial distribution of initial water saturation had caused viscous instability, lower viscosity reduction, lower displacement sweeps efficiency, and higher residual oil saturation. The present study is limited to spatial distribution in initial water saturation to a certain degree of heterogeneity. The heterogeneity in the spatial distribution of initial water saturation highly impacted the production performance of hot water flooding. The present study provides an idea for the implementation and future development of hot water flooding in a randomly initial water saturation distributed environment.

Experimental and Numerical Evaluation of Enzyme-Assisted Hot Waterflooding Performance for Heavy Oil Reservoirs

Abstract In this study, a systematical technique has been developed to experimentally and numerically evaluate enzyme-assisted hot waterflooding performance in a heavy oil reservoir for the first time. Experimentally, an enzyme solution (i.e., a protein-based liquid catalyst) is prepared and used to displace heavy oil in sandpacked experiments at elevated temperatures, during which pressures and fluid productions are continuously monitored and measured. Numerically, reservoir simulation is performed to reproduce the experimental measurements and then extended to evaluate the performance in a targeted heavy oil reservoir. Once history matching on the experimental measurements is completed, such a calibrated model is then employed to optimize enzyme concentration, temperature, and aging time, respectively. It is found from the displacement experiments that temperature imposes a significant impact on heavy oil recovery with its appropriate range of 45–55 °C, and enzyme positively contributes to heavy oil recovery for most scenarios. Compared to the traditional waterflooding mechanisms, the enzyme-assisted hot waterflooding process shows its considerable potential in heavy oil recovery by means of reducing oil viscosity, altering wettability, and reducing interfacial tension.

Can hot water injection with chemical additives be an alternative to steam injection: Static and dynamic experimental evidence

Steam injection has been proven to be a technically reliable and economically successful heavy oil recovery technique. However, the large amount of energy that is required to generate the steam, the high operational cost, as well as the environmental concerns are hindering the future applications of steam flooding. Reducing steam consumption and the associated greenhouse gas emissions in thermal-based heavy oil recovery methods is a great challenge in the heavy oil industry. A possible alternative to steam injection is hot water injection with chemical additives, especially in heavy oil reservoirs with some degree of mobility. In this paper, we performed static and dynamic evaluations on both conventional and novel chemicals as hot water additives. First, laboratory screening and evaluation for chemicals as hot water additives were performed at both 21 °C and 60 °C. Chemicals tested include the following: Span 80, silicon dioxide, diethylenetriaminepentaacetic acid (DTPA), switchable hydrophilicity tertiary amine (SHTA), and deep eutectic solvents (DESs). The evaluation was based on four selection criteria: emulsion stability, viscosity change, thermal stability, and chemical cost. Second, selected chemicals were further tested as hot water additives in sand-pack flooding experiments. Based on the overall static evaluations, four chemicals were selected for sand-pack flooding experiments at hot water conditions: DES 4, DES 9, SHTA, and SiO2 c. DES 11 and DTPA can still be used as alternatives, at least for core scale experimentations, but the extremely high cost can be a serious limitation to consider when assessing these chemicals for field trials. Dynamic sand-pack flooding experiments showed that all selected chemical additives could significantly improve the recovery factor compared to the hot water or steam injection without chemicals. The recovery factors of hot water injection with selected chemical additives reached 67 %–80.5 % which were much higher than that of steam injection without chemicals (38.8 %). Emulsification was found to be an important recovery mechanism of chemical additives in hot water flooding. The experimental results provided evidence that hot water injection with chemical additives might work as a good alternative to steam injection in improving the heavy oil recovery, reducing the cost, and lessening the environmental impact.

Effective equations for energy transport in petroleum reservoirs

Thermal enhanced oil recovery methods such as hot water flooding, steam drive, cyclic steam injection, steam-assisted gravity drainage, in-situ combustion, and electrical heating involve multiphase and multicomponent thermal flow with phase change and thermal displacement which improves the oil mobility inside the porous rock. Mostly, these methods are modeled by applying mass, momentum, and energy balances at the macroscale assuming that fluids and rock grains get instantaneously the same temperature, namely thermal equilibrium. In this paper, the macroscale energy equations are theoretically derived via the volume averaging method, considering: (1) local thermal non-equilibrium with and without phase change (four-equations models), (2) pseudo-local thermal non-equilibrium (two-equations model), and (3) local thermal equilibrium (one-equation model). The starting point for the derivation of the equations is the governing energy equations at the microscale for a four-phase system (water, oil, gas, and rock). The different effective equations are obtained as well as the closure problems allowing the numerical computation of the associated effective coefficients, for instance, the effective thermal conductivity tensor contained in the one-equation model was numerically calculated and compared against available experimental data, getting reasonable accuracy. The aforementioned models will allow studying the effect of considering the local thermal non-equilibrium behavior on thermal oil recovery methods. • The macroscale energy equations were derived via the volume averaging method. • The local thermal non-equilibrium with and without phase change is considered. • The numerical computation of the associated effective coefficients was obtained. • The effective thermal conductivity was numerically validated with experimental data.

A new computational approach to predict hot-water flooding (HWF) performance in unconsolidated heavy oil reservoirs

In this study, a new computational approach for predicting the performance of hot-water flooding in unconsolidated heavy oil reservoirs is presented. The proposed model predicts the changes in the oil–water viscosity ratio (μo/μw) by estimating the reservoir temperature distribution through porous media. Then, the dimensionless and normalized variables were redefined to forecast water fractional flow as a function of temperature and water saturation. Moreover, the proposed approach predicts the cumulative heavy oil production and recovery factor more accurately and with less required input data and runtime compared to commercial simulators such as CMG-STARS (computer modeling group), etc.Estimated results were validated using laboratory experimental data and numerical simulation outputs. A total of 4 core-flooding experiments were conducted at injection temperatures of 20–80 °C. Numerical simulation models based on the laboratory HWF tests were developed in CMG-STARS. The water–oil relative permeability curves were tuned to history match simulation results with those obtained from experiments.Finally, the predicted cumulative heavy oil productions, recovery factors (RF) and production rates by the proposed approach were compared to the results from the laboratory sandpacked tests and simulation runs for three scenarios. The relative errors between heavy oil recovery factors obtained from computational approach and experimental data were measured to be 11.01%, 14.51% and 13.69% for injection temperatures of 40, 60 and 80 °C, respectively.

Screening of waterflooding, hot waterflooding and steam injection for extra heavy crude oil production from Tatarstan oilfield

Thermal enhanced oil recovery techniques, especially steam injection, are the most successful techniques for extra heavy crude oil reservoirs. Steam injection and its variations are based on the decrease in oil viscosity with increasing temperature. The main objective of this study is the development of advanced methods for the production of extra heavy crude oil in the oilfield of the Republic of Tatarstan. The filtration experiment was carried out on a bulk model of non-extracted core under reservoir conditions. The experiment involves the injection of slugs of fresh water, hot water and steam. At the stage of water injection, no oil production was observed while during steam injection recovery factor (RF) achieved 13.4 % indicating that fraction of immobile oil and non-vaporizing residual components is high and needed to be recovered by steam assisted EORs.

Research Status and Prospect of Heavy Oil Recovery Technology

With the continuous exploitation of most reservoirs in China, the proportion of heavy oil reservoirs increases, and the development difficulty is greater than that of conventional reservoirs. In view of the important subject of how to improve the recovery factor of heavy oil reservoir, the thermal recovery technology (hot water flooding, steam flooding, steam assisted gravity drainage SAGD and steam huff and puff) and cold recovery technology (chemical flooding, electromagnetic wave physical flooding and microbial flooding) used in the development of heavy oil reservoir are summarized. The principle of action is analyzed, and the main problems restricting heavy oil recovery are analyzed The main technologies of heavy oil recovery are introduced from the aspects of cold recovery and hot recovery. Based on the study of a large number of literatures, and according to the development trend of heavy oil development, suggestions and prospects for the future development direction are put forward.

Numerical modeling of gas production from methane hydrate deposits using low-frequency electrical heating assisted depressurization method

With the increasing global demand for clean energy, methane hydrate has been regarded as a potential alternative energy source in future due to its huge resources and high energy density. In this study, a mathematical model is established to evaluate the production performance of low-frequency electrical heating assisted depressurization (LF-EHAD) method for hydrate deposits recovery. Within the framework of this model, the integral finite difference method and Newton-Raphson iteration are employed for solution, which is then validated by the experiment data. Using this model, the energy recovery behaviors with LF-EHAD from Shenhu hydrate deposits are investigated and then compared with those performed by hot water flooding and depressurization. Simulation results show that hydrate dissociation and gas production are significantly enhanced as a result of sufficient heat supplied by the electrical heating, validating the potential of the LF-EHAD for hydrate deposits recovery. After 2000 days of production, the cumulative gas production of LF-EHAD and hot water injection are 2.37 times and 1.47 times of that conducted by the depressurization method. Moreover, the heat consumption used to increase the formation temperature in the hydrate dissociation region under LF-EHAD is much less than that of hot water flooding, which results in a higher energy efficiency ratio (EER) of 9.65 for LF-EHAD, while the EER of hot water flooding is 4.42. Overall, LF-EHAD shows better performance than hot water flooding with the same amount of heat input because of higher gas production and energy utilization efficiency, but lower water production.

Enhancing hot water flooding in hydrate bearing layers through a novel staged production method

A method to improve the performance of hot water flooding in a hydrate bearing layer (HBL) is proposed. The development approach involves a horizontal production well completed by sliding sleeves and one vertical injection well. The horizontal section of the production well is first opened to yield a high production rate. As the gas production reduces to a certain degree, staged production from the toe to the heel is conducted by opening and closing the sliding sleeves. Subsequently, particle swarm optimization is coupled with a simulator to optimize the primary adjustable parameters. Furthermore, the proposed approach is compared with an un-staged approach and Sasaki’s approach. The results indicate that the optimal injected water temperature is 51.3 °C considering both energy efficiency and recovery. The optimal distance between the horizontal wellbore and the top of the HBL is approximately 1/3 of the reservoir thickness, and the unperforated interval of the injection well should cover the upper 2/3 of the HBL. Based on the same injected heat, the proposed approach can improve cumulative gas production by 25.6%, 14.4%, and 39.1% compared with the un-staged approach, Sasaki’s approaches 1 and 2, respectively.

Simulation Study of Hot Waterflood and WASP Injection Post Mature Steamflood

Steamflood is the most successful thermal EOR applied throughout the world and have produced the biggest portion of oil from EOR methods. As high intensity energy and associated cost are put to produce oil, optimization in any level can have tremendous impacts. Optimization in steamflood operation can be achieved by optimizing steam injection (rate, time), especially in mature pattern/ field or nearing the end of field life/ abandonment. This objective can be done thru utilization of retained heat in the reservoir and overburden/ underburden as they are not instantaneously produced with fluids. By using reservoir simulation, it can be shown that injection is not necessary to be continue until abandonment but can be stopped at a much earlier time hence a much profitable steamflood operation can be achieved.

Laboratory evaluation of an efficient low interfacial tension foaming agent for enhanced oil recovery in high temperature flue-gas foam flooding

Flue-gas foam/surfactant polymer flooding is a novel technology to enhanced oil recovery for heavy oil reservoir after hot water flooding with safety and efficiency. However, high temperature and the complex composition of flue gas greatly influence the foaming ability of the foaming agent, and weaken the plugging and profile control ability of the foam. Hence, screening suitable foam agents is of great significance. Here, a typical terpolymer of N‒methyl butenone carboxylates, alkyl phenyl sulfonates and pyrrolidone was selected as an efficient foam agent. The foaming performance and stability of the foam agent remained unchanged after 300 °C aged for 72 h in the flue gas atmosphere. Foam performance and stability tests in the simulative flue gas environment, adsorption properties of oil sands, and resistance factor evaluation were carried out. It showed good foam performance and stability, low adsorption capacity (0.77 mg/g), low interfacial tension (10−2 mN/m) and high resistance factor (>418), which indicated that the terpolymer (PNCAS) can reduce the gas channeling and increase the sweep area. The results of homogeneous and heterogeneous model experiments and microscopic mechanism suggested that foam flooding can greatly improve oil recovery while the low permeable sand-pack recovery can increase almost 42% in comparison with the conventional hot water flooding.

Suitability of hot urea solutions for wettability alteration of bitumen reservoirs – Simulation of laboratory flooding experiments

We report highly fine grid numerical simulation of sandpack flooding experiments conducted using 5 and 10 wt% hot urea solutions for wettability alteration of bitumen reservoirs. Another hot water flooding experiment was also simulated as a baseline for comparison with hot urea solutions. The relative permeability curves have been obtained through history matching of the experimental oil recovery. The results indicated that urea solutions have proved to be efficient in wettability alteration toward more water-wet and attenuation of viscous fingering leading to delayed water breakthrough as was confirmed by the shape of the relative permeability curves. Wettability alteration led to incremental oil recovery compared to the hot water flooding. It was shown that wettability alteration and the in-situ generation of water in oil (W/O) emulsions previously observed in experiments can be captured using the relative permeability curves. These results find application in the design and optimization of thermal bitumen recovery processes.

The basic principle of enhancing oil recovery technology in heavy oil reservoirs

Due to the heterogeneity of heavy oil reservoirs and the high viscosity of heavy oil, the recovery rate of heavy oil reservoirs is much lower than that of conventional reservoirs. So increasing the recovery rate of heavy oil reservoirs is of great significance to the goal of improving the technical level of heavy oil development proposed by the National Energy Plan. This paper outlines several commonly used techniques for improving the recovery of heavy oil reservoirs, including steam flooding, hot water flooding, polymer flooding, surfactant flooding, microbial flooding, foam flooding, ultrasonic viscosity reduction technology, etc. And briefly explains the basic principles. The internal causes of the problem are analyzed, and several focal points for improving the recovery of heavy oil that should be paid attention to are put forward.