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Molecular diffusion is critical for enhanced oil recovery (EOR) in shale oil reservoirs with complex fracture networks. Understanding the influence of fractures on diffusive mass transfer is crucial for predicting oil recovery and remaining oil distribution. Diffusive mass transfer between fractures and matrix is critical in comprehensively and effectively simulating molecular diffusion. Resolution of matrix cells significantly affects diffusion accuracy at the fracture–matrix interface. Low resolution results in multiple fractures in the same matrix cell, leading to decreased precision in calculating mass transfer by conventional methods. To address this, a novel multiphase and multicomponent model is proposed. The new model integrating the consideration of fracture spacing modifies molecular diffusion transmissibility between fracture and matrix in an embedded discrete fracture model. The discretization employs the two-point flux approximation in the finite-volume method. Validation compares the coarser mesh to the finest grid as a reliable reference. Results show the proposed model accurately captures diffusive mass transfer in a coarser mesh. Modified models study molecular diffusion's effects on EOR in shale oil reservoirs with complex fracture networks by CO2 huff and puff. Results indicate that increasing injection rates cannot improve oil recovery under extremely low porosity and permeability. Molecular diffusion facilitates CO2 penetration into the formation. This expands the swept CO2 volume and increases both volume expansion and formation energy. In addition, the light and heavy components of the crude oil are diffused into the fractures and eventually produced, which reduces gas production in the case of diffusion. [ABSTRACT FROM AUTHOR]

The high water cut stage is an important stage of the water injection development of oilfields because there are still more oil reserves available for recovery in this stage. Most oilfields have experienced decades of waterflooding development and adjustment. Although waterflooding reservoirs face the problems of the seriously watered-out and highly dispersed distribution of remaining oil, they remain dominant in waterflood development. This paper investigates the current situation of high-water content reservoirs and the methods available to improve oil recovery and elaborates on the fine reservoir description. Furthermore, it analyzes the main technical measures taken during the high water cut period, namely, secondary oil recovery waterflooding technology (including layer system subdivision, well pattern infilling, strengthening of water injection and liquid extraction, closure of high water cut wells, cyclic waterflooding technology, and water injection profile control) and tertiary oil recovery technology (represented by chemical flooding and gas flooding). In addition, this study reveals the mechanisms and effects of these methods on improving waterflooding development. Finally, this paper summarizes improved oil recovery technology and discusses the key directions and development prospects of this technology in enhancing the oil recovery rate. [ABSTRACT FROM AUTHOR]

Thermal recovery technology is generally suitable for shallow lays due to the higher thermal loss for the deep heavy-oil reservoirs. Non-thermal recovery technologies, such as the non-condensate gas injection technology, are not limited by the reservoir depth and could be extensively applied for the heavy-oil reservoir. Many experimental studies and field applications of non-condensate gas injection have been conducted in heavy-oil reservoirs. The injected non-condensate gas could achieve dynamic miscibility with heavy oil through multiple contacts, which has a significant viscosity-reduction effect under the reservoir conditions. In addition, the equipment involved in the gas injection operation is simple. There are many kinds of non-condensate gases, and common types of gases include N2 and CO2 due to abundant gas sources and lower prices. Moreover, CO2 is a greenhouse gas and the injection of CO2 into the reservoir would have environmental benefits. The non-thermodynamic method is to inject N2 and CO2 separately to produce heavy oil based on the mechanism of the volume expansion of crude oil to form elastic flooding and reduce crude oil viscosity and foamy oil flow. Steam injection recovery of the thermodynamics method has the disadvantages of large wellbore heat loss and inter-well steam channeling. The addition of N2, CO2, and other non-condensate gases to the steam could greatly improve the thermophysical properties of the injected fluid, and lead to higher expansion performance. After being injected into the reservoir, the viscosity of heavy oil could be effectively reduced, the seepage characteristics of heavy oil would be improved, and the reservoir development effect could be improved. Non-condensate gas injection stimulation technology can not only effectively improve oil recovery, but also help to achieve carbon neutrality, which has a very broad application prospect in the future oil recovery, energy utilization, environmental improvement, and other aspects. [ABSTRACT FROM AUTHOR]

Polyacrylamide (HPAM) and other traditional polymers have poor temperature resistance and salinity tolerance and do not meet the needs of high-temperature and high-salinity reservoirs. In this study, a new temperature-resistant and salinity-tolerant polymer QJ75-39 was synthesized using acrylamide (AM) as a hydrophilic monomer, 1-acrylamide-2-methylpropanesulfonic acid (AMPS) and N-vinylpyrrolidone (NVP) as functional monomers and DS-16 as a hydrophobic monomer. Through laboratory experiments, the properties (temperature resistance, salinity tolerance and aging stability), polymer injection and core displacement effect of the polymer were studied. The experimental results showed that the new polymer could meet the needs of polymer flooding technology in high-temperature and high-salinity reservoirs. Experiments showed that the polymer had a temperature resistance of 95 °C and a salinity tolerance of 1.66 × 105 mg/L. When the temperature was 95 °C and the TDS was 55,376.8 mg/L, the viscosity of the polymer was 31.3 mPa s, and the viscosity remained above 30 mPa·s after aging for 60 days. The polymer had good injectivity between 300 and 600 mD, and the injection pressure could reach equilibrium quickly. The oil recovery effectively increased with the grsowth in the amount of injected polymer. When the injection amount was 0.5 PV, the enhanced oil recovery was 20.65%. This study is of great significance for the application and popularization of polymer flooding technology in high-temperature and high-salinity reservoirs. [ABSTRACT FROM AUTHOR]

Previous studies on the technique for using the remaining oil are incomplete and inaccurate according to the position of the interlayer of the Steam-Assisted Gravity Drainage (SAGD) technique, and comparative studies of infilled horizontal wells are lacking. In this study, the SAGD well pair in the superheavy oil reservoir in the Z block in the Xinjiang Oilfield, China, was taken as an example. According to the reservoir's geological parameters and production parameters, a typical well group geological model was created for the first time. The model divided the well groups in block Z into three categories according to the position of the interlayer, the production degree of the horizontal section, the oil recovery ratio, and the available degree of reserve control. According to the geological classification results, different typical well groups without an interlayer, with an interlayer located above the steam injection well, and with an interlayer located between the well pairs were classified and analyzed using numerical simulations. This was the first time the infilled horizontal well technique was compared with the infilled vertical well-assisted SAGD technique. In addition, the steam chamber connection law of the infilled vertical well-assisted SAGD was clarified. The results show that for reservoirs without an interlayer, the use of infilled horizontal well-assisted SAGD could speed up the lateral connection of the steam chambers and reduce the residual oil saturation. For reservoirs with a low production degree in the horizontal section and that are affected by an interlayer, an infilled vertical injector could be used with the assisted SAGD technique to increase the oil recovery by 5%–13%. The results of this study provided strong guidance for the next step in using enhanced oil recovery techniques to achieve traditional SAGD production from superheavy oil reservoirs with an interlayer. [ABSTRACT FROM AUTHOR]

Foam flooding is one of the effective techniques during thermal recovery process in heavy oil reservoir. Nitrogen is generally co-injection with the foaming agent for the generation of foam. However, the mechanism has not been totally understood, thereby requiring further discussion. In this study, a series of sand pack experiments for nitrogen foam steam flooding were designed and conducted. A comparison of influencing factors, including gas-liquid (foaming agent) ratio, permeability, injection scheme, and oil saturation was used to evaluate the stability and blocking mechanisms of foam. The results show that the blocking capacity of the gas-liquid ratio of 1:1 is the greatest in all cases under high-temperature condition. The blocking mechanism of foam is analyzed, which indicates that foam is selective to block larger pores and throats in porous media with high-permeability. And also, the stability of foam becomes worse while meeting oil. This characteristic is favorable for improving the sweep efficiency to enhance oil recovery in developing heavy oil reservoir. [ABSTRACT FROM AUTHOR]

When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO 2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 °C. Thus, the solubility of CO 2 in super-heavy oil and its impact on decreasing viscosity beyond 150 °C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO 2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 °C were conducted to explore the effects of CO 2 on oil displacement efficiency. The results indicated that solubility of CO 2 became significantly lower at 200 °C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO 2 decreased by 71.2%, and relative density decreased by 10.1% at 200 °C compared to those of degassed crude. At temperatures of 120 °C, 150 °C and 200 °C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 °C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO 2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO 2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs. [ABSTRACT FROM AUTHOR]

A one-dimensional long core displacement experiment was designed based on injection of pure foam liquid, air, and air-foam system into the tight matrix core and fracture core. This aimed to verify the individual injection capacity of these materials in the ZenPing well area in a typical tight oilfield, China. The results indicate that the air-foam system cannot be injected directly into the tight matrix core. However, because some of the foaming agent is absorbed by the reservoir rock, causing foam collapse, the defoamed liquid and separated air can flow into the tight matrix core, which results in stable displacement. Three-core parallel displacement experiments were designed, including two matrix cores (with permeability difference ratios of 10) and one fractured core. The results indicated that the air-foam system mostly flows into the fractured core and blocks the fractures. Thereby, some of the defoamed liquid and separated air could flow into the matrix core to displace the residual oil. The residual oil saturation and the oil displacement efficiency were 21.12% lower and 32.89% higher, respectively, than those of water flooding. We also analyzed the profile-controlling mechanisms, which indicated the air-foam system flooding is capable of improving performance following water flooding. We recommend that water flooding should be switched to air-foam system flooding as early as possible before the water cut reaches around 90%. Our findings were successfully used to guide a pilot test of the ZenPing well area. The results indicate that air-foam flooding is a feasible means for improving oil recovery in tight oil reservoirs. [ABSTRACT FROM AUTHOR]

A series of experiments was conducted to quantify foamy oil recovery under different conditions, including the pressure depletion rate, solution gas-oil ratio (GOR), and oil viscosity. As indicated by the experimental results, at higher-pressure depletion rates, solution GOR, and oil viscosity, the foamy oil ultimate recovery tends to be higher. The foamy oil phenomenon can occur when the pressure depletion rate, solution GOR, and oil viscosity exceed certain values. Based upon experimental results, multiple regression analysis was used to establish a mathematical expression of the relationship between dimensionless foamy oil recovery ( R eD ) and the main factors affecting it, including the dimensionless pressure depletion rate (Δ p rD ), the dimensionless solution GOR ( R sD ), and the dimensionless oil viscosity ( μ D ). The computed results showed the weighted values of the effects of lnΔ p rD , ln R sD , and ln μ D on ln R eD to be 0.653, 0.211, and 0.136, respectively, which indicates that improving the pressure depletion rate may be the most effective approach to increasing the amount of foamy oil recovered. The uses and limitations of the correlation were validated using verification experiments and are discussed. Suggestions for rendering foamy oil recovery more efficient can provide useful guidance for the development of heavy hydrocarbon reservoirs. [ABSTRACT FROM AUTHOR]

To promote CO 2 utilization and protect the environment, CO 2 is often employed to enhance oil recovery. Meanwhile, injection of CO 2 –CH 4 mixtures can offer better mobility ratios and delay water breakthrough resulting in the favorable oil sweep efficiency. The gas-alternating-water (WAG) flooding in rhythmic hydrocarbon reservoirs has been studied by simulation software. The difference between water and CO 2 –CH 4 flooding lies in the different density and viscosity among CO 2 , CH 4 , oil and water. Water tends to displace oil along the lower reservoir; inverted rhythmic reservoir may slow down the trend. CO 2 and CH 4 tend to displace oil along the middle-upper and upper reservoir, respectively; positive rhythmic reservoir may slow down the trend. Therefore, a homogeneous reservoir should be given priority in WAG flooding, followed by positive rhythmic reservoir. [ABSTRACT FROM AUTHOR]

Laboratory experiments and pilot applications have proved that urea is an efficient agent to enhance heavy oil recovery. Numerous studies have been conducted to investigate the mechanisms of urea co-injection process in steam flooding or cyclic steam stimulation. However, investigations of applying urea in steam assisted gravity drainage (SAGD) process are rarely published. The mechanism of enhanced oil recovery in the urea assisted SAGD process has not been fully understood. Laboratory experiments and numerical simulations were conducted to study the decomposition rate of urea, the effect of urea decomposition products on reservoirs and pipelines, and the distribution of effective decomposition products of urea in the steam chamber at conditions of different concentrations, temperatures, and injection rates. The results show that the solubility of the effective urea decomposition products affects their distribution in the formation because of the huge difference between the solubility in oil and water. In SAGD process, urea cannot be completely decomposed and will produce solid decomposition products, which could block the reservoir pores and production pipelines in certain conditions. Moreover, numerical simulation indicates that the use of low-concentration urea injection in SAGD can effectively enhance oil recovery and oil production rate, while high-concentration urea can reduce the oil recovery and oil production rate. In addition, it was proved that CO 2 mainly exists at the edge of the steam chamber and NH 3 is distributed in the irreducible water near the well-bore. CO 2 is more effective than NH 3 for enhancing oil recovery in urea assisted SAGD. Studies indicate that urea co-injection is a feasible method for enhancing oil recovery in the SAGD process. [ABSTRACT FROM AUTHOR]

• An innovative nanofluidic chip was designed and developed for measuring the minimum miscibility pressure of CO2-shale oil. • A novel thermodynamic model of phase equilibrium was developed by integrating simplified local density functional theory. • The phase behavior of CO 2 -shale oil and the variation rule of MMP at different scale pore sizes were explored. In recent years, CO 2 enhanced oil recovery has gained traction in shale oil reservoirs. Shale oil reservoirs are characterized by numerous nanopores, where shale oil exhibits unique phase behavior due to nano–confinement effects. Traditional theoretical model and microfluidic experiment often fail to accurately depict the minimum miscible pressure (MMP) of CO 2 –shale oil in nanopores. In this study, nanofluidic experiments were conducted to investigate the MMP of CO 2 –alkanes in single pore channels and porous media channels with depths of 30 nm and 100 nm. Additionally, a novel thermodynamic model of gas–liquid–adsorbed phase equilibrium, which considers the capillary force and the shift in the critical property, was developed by integrating simplified local density functional theory. The feasibility of the method was determined by comparing the measured MMP with the MMP obtained using the newly established thermodynamic model, resulting in errors of 10.804 % and 5.545 %. Finally, phase behavior and MMP for two typical oil samples in block A in China were conducted using the newly established thermodynamic model. The results revealed that as the pore radius decreases, the area of the two–phase region enclosed by the phase envelope contracts progressively. In addition, the saturation pressure decreases gradually for shale oil with a higher content of light components as the molar fraction of the injected CO 2 increases, whereas for shale oil with higher heavy component content, it increases as the CO 2 molar fraction increases. The MMP of CO 2 –shale oil in 10 nm pores is 70.188 bar at 392.75 K of sample 1 and 83.007 bar at 374.72 K of sample 2. Compared to the bulk phase, the MMP was reduced by 63.76 % and 57.64 %. [ABSTRACT FROM AUTHOR]

Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO 2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57–200 °C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO 2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 °C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO 2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO 2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs. • Mechanisms of water breakthrough of hot water flooding was studied. • A surfactant with good foamability and stability was screened out for high temperature CO 2 foam flooding. • Mechanisms of improving oil recovery of high temperature CO 2 foam flooding were investigated. • High temperature CO 2 foam flooding was verified to be a promising strategy following hot water flooding. [ABSTRACT FROM AUTHOR]

Steam assisted gravity drainage (SAGD) has already been successfully applied in the recovery of extra-heavy oil reservoirs. However, it has been demonstrated that extra-heavy oil above shale barriers is hard to be recovered and SAGD performance is significantly limited. In this study, a novel well pattern called herringbone injector-horizontal producer assisted gravity drainage (HI-SAGD) was proposed to recover the oil above shale barriers. A series of numerical simulations were conducted to investigate the feasibility and operation strategies of HI-SAGD. The mechanisms of applying HI-SAGD to enhance oil recovery were investigated. The sensitivities of shale barrier characteristics and branches of the herringbone injector were analyzed. The results from numerical simulations show that conducting HI-SAGD with appropriate strategies can significantly improve performance. The necessary start-up strategy is to conduct two cycles of cyclic steam stimulation (CSS) after steam circulation. Thus, oil above the shale barrier can be recovered. Higher oil rate can be achieved in the early stage of the process, and oil recovery factor is improved. Field application and numerical simulations show that HI-SAGD is a promising technology for the recovery of extra-heavy oil reservoirs, especially with shale barriers above the injector. • HI-SAGD was proposed to be a promising technology to recover extra-heavy oil reservoirs. • Appropriate start-up strategy was studied to realize the potential of herringbone branches. • Mechanisms and effects of herringbone well above the shale barrier were studied. • Shale barriers can influence the SAGD performances and the drilling strategy. [ABSTRACT FROM AUTHOR]

Abstract The primary recovery of conventional heavy oil (with viscosity <150 mPa s) in deep reservoirs often has a low recovery factor (RF) and high-pressure drawdown. It is important to propose effective and economic recovery methods to enhance oil recovery of these reservoirs. A top-driving, carbon dioxide (CO 2)-assisted hot-water flooding method is developed and presented in this paper. Laboratory experiments, including CO 2 solubility and one-dimensional (1D) core flooding tests, were conducted based on oil samples from a deep and pressure-depleted conventional heavy oil reservoir. Numerical simulations were conducted to study and discuss the mechanisms. The results from laboratory experiments show that the dissolved CO 2 in the oil reduced the oil viscosity by 30% at 57 °C and 2.0 MPa, and the displacement efficiency of carbonated 120 °C hot-water flooding was comparable to that of 200 °C steam flooding. The CO 2 -assisted hot-water flooding method requires substantially less energy input than the steam flooding method. Numerical simulation indicates that the CO 2 and hot-water co-injecting process results in viscosity reduction, increased pressure, increased sweeping volume, and, consequently, improved oil recovery. The top-driving and CO 2 -assisted hot-water flooding method provides a technical and cost-effective method for enhancing oil recovery in the post-primary recovered heavy oil reservoirs. Highlights • CO 2 solubility both in oil and water were tested under various temperatures and pressures. • Experiments of water, steam, carbonated water, and CO 2 flooding were conducted at various temperatures. • CO 2 -assisted hot-water flooding was designed with a flexible and adaptable well pattern. • Mechanisms and performances of the proposed method were illustrated by numerical simulations. • CO 2 -assisted hot-water flooding process is an economically effective method to recover deep heavy reservoirs. [ABSTRACT FROM AUTHOR]

Steam huff and puff has become one of the most widely used technologies to enhance oil recovery during the early phase in heavy oil reservoirs. However, when the development entered in the later phase gradually, the production performance had characteristics with low oil-to-steam ratio and the oil recovery is generally 20–30%. Predecessors usually study a certain follow-up method for a block, and the well pattern is very regular. For the oilfield in the later phase of steam huff and puff, there was a lack of systematic comparison and evaluation with different follow-up methods under irregular well patterns. In this paper, the heavy oil reservoir in block G of Liaohe oilfield was taken as an example. In view of the complex geological conditions and irregular well pattern, the follow-up developing strategies, steam flooding (SF), steam assisted gravity drainage (SAGD) and fire flooding (FF) were compared and evaluated by numerical simulation. A model with seven components and four reactions (used in FF) was established by using STARS module of CMG software. A variety of combined well patterns with vertical and horizontal wells were designed for comparing the production performance. In total, two cases of SF, three cases of SAGD, and two cases of FF were simulated and the oil recovery were studied. The results indicated that these follow-up development methods can enhance oil recovery in different degrees. The combined well pattern with vertical and horizontal wells had a better production performance than that of only vertical wells. In the study, the performance of FF with the horizontal well was the best (oil recovery was 31.7% in the 20th year; cumulative air oil ratio was 3973 m3/m3; final oil recovery was 54.6%), while the SAGD with one horizontal well was the worst (oil recovery was 15.3% in the 20th year; cumulative steam oil ratio was 17.7 t/m3; final oil recovery was 32.6%). Compared with SAGD and FF, the performance of SF was not the best and far from the worst (oil recovery was 40.3% in the 20th year; cumulative steam oil ratio was 12.7 t/m3; final oil recovery was 40.3%). The results show that when the well pattern conditions are complex, the number of wells is large, and the formation is heterogeneous, the SAGD of the vertical and horizontal well combination is obviously affected by the inter well interference. Meanwhile, SAGD production has certain delay and high water cut. It seems that the production performance of SF is not affected by horizontal wells, and the water cut is high. FF with horizontal wells has obvious production performance and can find more uniform formation temperature rise and stable water cut between 0.5 and 0.7. • A relatively comprehensive study of thermal recovery methods in heavy oil reservoir after steam huff and puff are compared. • The performance of steam flooding, SAGD, fire flooding for irregular well patterns are summarized based on simulations. • The combinations of vertical and horizontal well patterns in the heterogeneous reservoir are evaluated. • The development adaptability of the heterogeneous reservoir with irregular well patterns are analyzed and concluded. [ABSTRACT FROM AUTHOR]