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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]

In situ combustion (ISC), an efficient and economical method for enhancing heavy oil recovery in high-pressure, high-viscosity, and thermally challenged reservoirs, relies on the kinetics of crude oil oxidation. Despite an increased focus on kinetic models, there is a gap in understanding how oxidation kinetic parameters impact ISC effectiveness in heavy oil reservoirs. This study addresses this by selecting heavy oil samples from the G Block in the Liaohe oilfield and the M Block in the Huabei oilfield and conducting ramped temperature oxidation (RTO), pressure differential scanning calorimetry (PDSC), and thermogravimetric analysis (TGA) experiments. RTO detailed the thermal conversion process, categorizing oxidation into low-temperature oxidation (LTO), fuel deposition (FD), and high-temperature oxidation (HTO) stages. PDSC and TGA provided thermal characteristics and kinetic parameters. The feasibility of fire flooding was evaluated. Using CMG-STARS, an ISC model was established to analyze the impact of kinetic parameter changes. Activation energy significantly affected coke combustion, while the pre-exponential factor had a notable impact on cracking reactions. The recommended values for activation energy and the pre-exponential factor are provided. This study not only guides fire flooding experiments but also supports field engineering practices, particularly for in situ combustion in heavy oil reservoirs. [ABSTRACT FROM AUTHOR]

In the process of steam injection development of heavy oil, due to the serious heterogeneity and interference of steam channeling in the high-permeability layer, there is a lot of oily sludge in the produced liquid of oil wells, which is difficult to deal with. According to existing profile control technology and the related properties of oily sludge, a profile control system was developed by using oily sludge as the main agent and by adding other additives. At the same time, the properties of sludge, the matching relationship between the particle size of sludge and the formation of pore roar, the temperature resistance, the plugging ability, and other contents were studied. The agent featured an adjustable curing time (3 to 300 h) and resistance to pressures greater than 6 MPa and temperatures greater than 350 °C. After the agent was injected into the high-permeability steam channeling, the system was cemented with the formation rock and the sealing rate was more than 85%, without any damage to the low- and medium-permeability layers. According to the different characteristics of the production well and steam injection well, the construction technology was optimized, the oily sludge profile control technology suitable for heavy oil reservoirs was formed, and the field test was carried out. At present, more than 150 wells have been used in the field, with a cumulative oil increase of 10,756 tons. The technology not only solves the environmental pollution caused by oily sludge but also reduces the cost of thermal recovery of heavy oil, with great significance for improving the final recovery efficiency and commercial benefits of the oilfield. [ABSTRACT FROM AUTHOR]

Heavy oil reservoirs are often characterized by high viscosity and poor mobility, which is more complex with the presence of bottom water. The conventional vertical well development method has low oil recovery efficiency and limited controlled reserves of a single well. In addition, water cut can increase dramatically when the edge-bottom water breaks through. Horizontal well and CO2 huff-n-puff is an effective alternative development model for heavy oil reservoirs. This development method makes efficient use of CO2 and accords with the "Carbon Capture, Utilization, and Storage (CCUS)". The horizontal well can increase the drainage area. The dissolution of CO2 improves the mobility of crude oil and increases formation energy. In this paper, we established numerical simulation models based on the Liuguanzhuang oilfield in Dagang. The characteristics and producing rules of the horizontal well and CO2 huff-n-puff development in the heavy oil reservoir were studied. The results show that the production characteristics of horizontal well and CO2 huff-n-puff were similar to Steam-Assisted Gravity Drainage (SAGD). CO2 forms a viscosity reduction area above the horizontal well and the heavy oil flows into the wellbore due to gravity after viscosity reduction. The CO2 huff-n-puff can effectively enhance the production area of horizontal wells compared with the depletion development. However, the improvement in the production area gradually decreased as CO2 huff-n-puff cycles continued. There was a boundary of production area against the horizontal well, with the main production of heavy oil occurring at the upper and either end of the horizontal well. The CO2 huff-n-puff has a restraining effect on the edge-bottom water, which is confirmed via the proposed theoretical model. [ABSTRACT FROM AUTHOR]

There are large, heavy oil reserves in Block X of the Xinjiang oilfields, China. Due to its large burial depth (1300 m) and low permeability (26.0 mD), the traditional steam-injection technology cannot be used to obtain effective development benefits. This paper conducts experimental and simulation research on the feasibility and mechanism of CO 2 -energized fracturing of horizontal wells and N 2 foam huff-n-puff in deep heavy oil reservoirs with low permeability in order to further explore the appropriate production technology. The foaming volume of the foaming agent at different concentrations and the oil displacement effect of N 2 foam at different gas/liquid ratios were compared by the experiments. The results show that a high concentration of foaming agent mixed with crude oil is more conducive to increasing the foaming volume and extending the half-life, and the best foaming agent concentration is 3.0∼4.0%. The 2D micro-scale visualization experiment results show that N 2 foam has a good selective blocking effect, which increases the sweep area. The number of bubbles per unit area increases as the gas/liquid ratio increases, with 3.0∼5.0 being the optimal gas/liquid ratio. Numerical simulation results show that, when CO 2 -energized fracturing technology takes into account the advantages of fracturing and crude oil viscosity reduction by CO 2 dissolution, the phased oil recovery factor in the primary production period can reach approximately 13.7%. A solvent pre-slug with N 2 foam huff-n-puff technology is applied to improve oil recovery factor following primary production for 5∼6 years, and the final oil recovery factor can reach approximately 35.0%. The methodology formulated in this study is particularly significant for the effective development of this oil reservoir with deeply buried depth and low permeability, and would also guide the recovery of similar oil deposits. [ABSTRACT FROM AUTHOR]

In order to accurately predict geomechanical parameters of oil-bearing reservoirs and influencing factors of volumetric fracturing, a new method of geomechanical parameter prediction combining seismic inversion, well logging interpretation and production data is proposed in this paper. Herein, we present a structure model, petrophysical model and geomechanical model. Moreover, a three-dimensional geomechanical model of a typical reservoir was established and corrected using history matching. On this basis, a typical well model was established, 11 influencing factors of volume fracturing including formation parameters and fracturing parameters were analyzed and their impact were ranked, and the oil recovery rate and the accumulated oil production before and after optimal fracturing were compared. The results show that with respect to formation parameters, reservoir thickness is the main influencing factor; interlayer thickness and stress difference are the secondary influencing factors; and formation permeability, Young's modulus and Poisson's ratio are the weak influencing factors. For a pilot well of a typical reservoir, the optimized fracture increased production by 7 tons/day relative to traditional fracturing. After one year of production, the method increased production by 4 tons/day relative to traditional fracturing, showing great potential in similar oil reservoirs. [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]

In the process of waterflooding development of heavy oil, W/O emulsion has a strong ability to improve the mobility ratio and block the high-permeability layer, which can effectively improve the sweep coefficient and enhance oil recovery. In this paper, the stability and droplet size distribution of emulsions under different conditions were studied by taking heavy oil and formation water from Jimusar Oilfield in Xinjiang as samples. On this basis, double-pipe core flooding experiments were carried out to study the shut-off ability and oil displacement efficiency of W/O emulsion, and then a numerical simulation was carried out. The results show that oil and water can be completely emulsified when the stirring speed is higher than 4000 r/min. A stable emulsion can be formed when the experimental temperature is lower than 60 °C. A lower water cut results in a more stable emulsion. The emulsion is difficult to stabilize after the salinity exceeds 10,000 mg/L. When the pH value is about 7, the stability of the emulsion is the worst. With the increase in stirring speed, the increase in temperature, and the decrease in water content and salinity, the emulsion droplet size range is relatively concentrated, and the average particle size is smaller. In heterogeneous reservoirs, the permeability of different percolation channels is quite different, such that the displacement fluid only percolates along the high-permeability channel and cannot drive oil effectively. The results of displacement experiments show that the emulsion with a water cut of 60% has high viscosity and obvious sweep ability, but its stability is very poor; the effect is opposite when the water cut is less than 40%. The shut-off ability of W/O emulsion disappears gradually when the permeability contrast is more than 5.92. The research results are of great significance for improving oil recovery in heterogeneous heavy oil reservoirs. [ABSTRACT FROM AUTHOR]

To resolve the issues of the high porous medium flow resistance, low oil production rate, high oil decline rate, and low oil recovery factor for the cyclic steam stimulation (CSS) of horizontal wells in heavy oil reservoirs, the CSS method assisted by the electric heating (E-CSS) of horizontal wells was proposed in this study. Combining the heat from electric heating and steam during E-CSS, the analytical model of formation temperature rise was established for the three phases of electric-assisted CSS (i.e., injection, soaking, production), and physical experiments were carried out to compare the performance of conventional CSS and E-CSS. The experimental results were used to validate the analytical model and reveal the impact of the key electric heating mechanism on the horizontal CSS performance. Meanwhile, the typical well model was used to forecast the E-CSS potential. The results indicate that electric heating can achieve uniform heating in the steam injection phase, maintain heating around the wellbore in the soak phase, and reduce flow resistance and enhance oil output in the production phase. Forecasts of the typical well model indicate that electric heating can enhance the oil recovery factor by 9.4% and the oil-steam ratio from 0.14 to 0.23, implying a significant application potential in heavy oil reservoirs developed by horizontal CSS. [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]

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field. [ABSTRACT FROM AUTHOR]

A field test in the Xinjiang oilfield in China shows that the viscosity of heavy oil has a certain influence on the combustion dynamics and injection-production performance of fire flooding. The experiment in this study uses a one-dimensional combustion tube to study the temperature, gas composition, and air injection pressure and the production performance of the fire flooding of heavy oil with different viscosities. The results show that the oil viscosities of 1180–22500 mPa·s can achieve stable combustion, and the O2 content of the gas produced during the stable combustion stage is <0.5%. The higher the viscosity of the heavy oil, the higher the temperature in the burned zone and the smaller the range of the temperature increase in the unburned zone. The air injection pressure will increase rapidly until a stable seepage channel is formed, and then, it will drop to a level close to the formation pressure. High-viscosity heavy oil requires a higher air injection pressure and will remain in the high-pressure stage for a longer period of time. Low-viscosity heavy oil has a low water cut in the early stage of fire flooding, a large oil production rate, and a low and stable air–oil ratio. The water cut of high-viscosity heavy oil increases rapidly in the early stage of fire flooding and then decreases gradually, so a good air–oil ratio can only be obtained in the middle and late stages of fire flooding. Thus, fire flooding may be more suitable for application in common heavy oil and some extra heavy oil reservoirs with lower viscosities. [ABSTRACT FROM AUTHOR]

Due to the difference in oil and water density, the wellhead pressure continues to decrease with water-cut rising in deep-water volatile oilfields. Once it is close to the lower limit, the production well will stop flowing. This phenomenon seriously affects the production and recoverable reserves. By taking the dynamic relative permeability which can reflect the macroscopic movement of oil and water in the reservoir as an intermediate bridge, production performance has been combined with dominant reservoir factors, including reservoir structure, reservoir connectivity, and heterogeneity. By the statistical analysis of actual data, this paper clarified the quantitative relationships between dominant reservoir factors and production performance and established the refined prediction methods for production dynamics including water-cut and liquid production rate. A prediction method for the wellhead pressure was further established, and the flow-stop time of single well can be accurately predicted. The results can be used in annual production forecast and recoverable reserve evaluation. This method had been successfully applied in Akpo oilfields in the Niger Basin. The results show that the production dynamics are significantly affected by reservoir factors in deep-water turbidite sandstone reservoir and the prediction method considering reservoir factors will be much more applicable. In deep-water volatile oilfields, the flow-stop risk of the production well in middle and high water-cut stages is very great and is mainly affected by the water-cut and liquid production rate. Judging from the application effect of Akpo oilfields, this method has high prediction accuracy and can be used to guide optimization and adjustment in deep-water oilfields. [ABSTRACT FROM AUTHOR]

Dynamic fractures are a geological attribute of water flooding development in tight fractured oil reservoirs. However, previous studies have mainly focused on the opening mechanism of dynamic fractures and the influence of dynamic fractures on development. Few attempts have been made to investigate the optimization of the dynamic fracture parameter. In this study, the inverted square nine-spot well pattern model is established by taking fractured reservoir's heterogeneity and its threshold pressure gradients into account. This simulation model optimizes the various parameters in a tight fractured oil reservoir with dynamic fractures, that is, the intersection angle between the dynamic fractures and the well array, the number of dynamic fractures, the penetration ratio, and the conductivity of the oil well's hydraulic fractures. The results of this optimization are used to investigate the oil displacement mechanism of dynamic fractures and to discuss a mechanism to enhance oil recovery using an inverted square nine-spot well pattern. The simulation results indicate that a 45° intersection angle can effectively restrain the increase in the water cut. A single dynamic fracture can effectively control the displacement direction of the injected water and improve the oil displacement efficiency. Moreover, the optimal penetration ratio and the conductivity of the hydraulic fracture are 0.6 and 40 D-cm, respectively. [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]

Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 °C, and steam superheated by 40 °C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 °C, steam superheated by 10 °C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C 22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C 34 . This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery. [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]

The presence of significant amounts of injected steam and heat loss are unavoidable issues occurred that are observed during the steam-assisted gravity drainage (SAGD) process in developing heavy oil reservoirs. Because of these limitations and concerns, non-condensable gas co-injection has become a potential technique to enhancing oil recovery and reducing energy consumption. However, the oil production mechanism is complicated and has not been totally understood, thereby requiring further discussion. In this work, a two-dimensional physical model was designed to investigate the production mechanisms of nitrogen on SAGD. Two comparative injection schemes, specifically the conventional SAGD and nitrogen assisted SAGD (NA-SAGD), were conducted to investigate the effect of nitrogen co-injection with steam on the SAGD performance. Dynamic temperature profile changes during the two experiment processes were monitored and recorded. The observation results indicate that nitrogen accumulation at the upper part of the model resulted in the effective expansion of the NA-SAGD process steam chamber along the horizontal direction. The swept area of steam increased significantly and the residual oil saturation was reduced. The cumulative oil production of NA-SAGD was higher than that of the conventional SAGD. Moreover, the apparent heat loss reduction, which defines the heat utilization efficiency, exhibited an increase following nitrogen injection. In addition, a numerical simulation was generated to compare and verify the results obtained in the two experiments. Nitrogen co-injection with steam effectively enhanced the oil recovery. Studies indicate that NA-SAGD is a feasible method for improving oil production in developing heavy oil reservoirs. [ABSTRACT FROM AUTHOR]

Effective communication in the well pair during the preheating period has a significant effect on the success of the production period by using steam-assisted gravity drainage (SAGD) technology in heavy oil reservoirs. However, the time-consumption and the economic cost associated with steam generation and circulation limit the application of this technique. Because of these limitations and concerns, we have investigated the effectiveness of the solvent injection-assisted start-up period. A sand-pack physical experiment was designed to evaluate the effect of solvent on heavy oil-viscosity reduction. Different solvents were tested to examine the effects on viscosity reduction and asphaltene precipitation. Xylene was selected as asphaltene-soluble solvent for this experiment. The solvent was injected at different injection rates and diffused into the bitumen during the soaking period. Furthermore, a numerical model was constructed to simulate the performance of the preheating and early production period with or without solvent injection in the start-up process. The observations and simulation results indicate that the injected solvent diffuses to improve the sweep area to further reduce oil viscosity significantly in the soaking time. However, too long soaking time results in lower concentrations of solvent has the opposite effect on oil-viscosity reduction. The relative permeability of the oil phase increases as well. Whereas, according to numerical simulation, the solvent-assisted start-up process of SAGD shortens preheating time and reduces steam consumption. Both the production rate and the cumulative oil production improve during the early production period. [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 general framework is developed in regional heterogeneous reservoirs. • Arbitrary boundary shape is considered in the model. • New solutions for fractured horizontal well with finite conductivity are obtained. The focus of this paper is to establish a new general model framework considering both hydraulic fractures with finite conductivity and heterogeneous characteristics of multiple connected regions by using boundary element method. With this framework, we can calculate the pressure performance of any heterogeneous reservoir. The innovation is that the complex fracture flow, boundary shape and heterogeneous characteristics can be flexibly considered in the model. Transient pressure of fractured horizontal wells in heterogeneous reservoir is obtained by using Stehfest numerical inversion method. Subsequently, this proposed regional heterogeneity model was validated by using numerical simulation methods. The results show that the proposed heterogeneous model can be divided into five flow segments, which are bilinear flow, linear flow, radial flow, first boundary dominated flow and second boundary dominated flow. However, the research results show that the presence or absence of some flow sections is closely related to the regional permeability ratio and the regional storage capacity ratio. As the two most important parameters of heterogeneous reservoir, the permeability ratio and regional storage capacity of heterogeneous reservoir will have a huge impact on the pressure response and pressure field. The sensitivity analysis shows that these two factors will lead to the deformation of the pressure field distribution and affect the flow characteristics, and cause some flow segments to fail to appear. The smaller the regional storage capacity ratio, the deeper the V-shape, and the more fluid supplied from the outer zone to the inner zone. This study also suggests that the fracture conductivity mainly affects the early flow characteristics, and the smaller the conductivity, the greater the pressure loss. In addition, irregular boundary will also cause important deformation of pressure field, and the area size will affect the late flow characteristics, and the smaller the area, the greater the pressure loss. The new semi-analytical solutions can form a series of typical curves and be applied to the well test analysis of multi-stage fracturing horizontal wells in heterogeneous and unconventional oil and gas reservoirs. The findings of this study can help for better understanding of the influence of reservoir heterogeneity on pressure response and find some applications in well testing for inverse problems in heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

• The adaptability of crude oil samples to fire flooding was analyzed by combustion tube tests and DSC tests. • A special combination well pattern of horizontal and vertical Wells named stereoscopic fire flooding was put forward. • A concept of oil recovery potential (ORP) after oxygen breakthrough in horizontal production wells in fire flooding was proposed. • The influence factors of stereoscopic fire flooding were studied and the conclusions were drawn. In-situ combustion (ISC) or fire flooding (FF) technology had been widely applicated in developing heavy oil reservoirs. Due to the complex physical and chemical processes, it is not easy to guarantee the high oil recovery. For thin layer reservoirs, vertical well mode of FF can achieve good results, but for thick layer reservoirs, the vertical producing degree of FF under vertical well pattern is low. Therefore, it is necessary to deepen the basic understanding of fire flooding under different well patterns and study the influencing factors for thick heavy oil reservoir. Stereoscopic fire flooding (SFF) mode is proposed in this paper, and the one-dimensional combustion tube and differential scanning calorimetry (DSC) experiments were introduced and designed. The heavy oil samples of G block in Liaohe oilfield in China were studied and the oxidation kinetic parameters were obtained by experiments. The applicability of oil samples for fire flooding was tested. The different fire flooding modes was compared and the influencing factors of SFF were analyzed through simulations. The results indicated that the temperature of high temperature oxidation (HTO) was above 450 °C. The CO 2 content of the produced gas was more than 13% and the apparent HC atomic ratio was 1.28. DSC experiments showed the activation energy of HTO stage was 1.40 × 105 J/mol. The results indicated that the heavy oil samples can reach a high temperature combustion state. The SFF mode was simulated by CMG-STARS module based on the experimental results. The simulation results showed that SFF had better performance than FF of only vertical wells in oil recovery. The important factors of SFF, such as gas-injection rate, reservoir thickness, transverse permeability, vertical permeability, crude oil viscosity, formation dip angle and relative position of horizontal wells and the applicable conditions of SFF mode were analyzed and the optimum condition for SFF mode for each influencing factor was analyzed, and the conclusions were obtained. [ABSTRACT FROM AUTHOR]

Highlights: [•] The HTHP visualized experimental system was used to study the foamy oil stability. [•] A serial of experiments were evaluated the performance of the foam stability. [•] The foamy bubbles exist much longer at the actual reservoir conditions. [•] The results were used to guide the development of Block MPE-3 in Venezuela. [Copyright &y& Elsevier]

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]

Abstract Steam-Assisted Gravity Drainage (SAGD) has been demonstrated as an effective process for recovering extra-heavy oil. However, large volumes of steam are required to heat the viscous oil, resulting in high consumption of natural gas and water, which affects its economic benefit. Therefore, research has long focused on improving the SAGD performance. In this study, a viscosity reducer (VR) assisted SAGD (VR-SAGD) process is systematically examined by experiment and numerical simulations based on an extra-heavy oil sample from a commercial SAGD block in Xinjiang oil fields, China. A scaled two-dimensional (2D) VR-SAGD experiment is carried out using a scale model to study the mechanisms of production dynamics and to observe the steam chamber development phases of the VR-SAGD process. A history match is conducted based on the 2D experimental data, and the recovery mechanisms of VR-SAGD are discussed. Heterogeneity in terms of barriers sandwiched in the pay zone is studied, and operational parameters are optimized based on the history match results. The 2D physical simulation results show that VR-SAGD accelerates the oil rate by a factor of 1.74 and reduces the instantaneous steam-to-oil-ratio by 49.7%. The VR co-injected with steam propagates in advance and accumulates at the front of the steam chamber and around the barriers to accelerate the effect of viscosity-reduction and reduce the heat loss to the overburden. Numerical simulation results indicate that the optimum time for VR injection is during and after the phase when the steam chamber expands sideways. The optimized VR/steam volume ratio and production/injection volume ratio are 1:9 and 1.2:1, respectively. The VR-SAGD process shows good potential to improve post-SAGD performance and reduces steam consumption in extra-heavy oil reservoirs. Highlights • A scaled 2D experiment was conducted to study the mechanism of viscosity-reducer (VR)-assisted SAGD (VR-SAGD). • History match with a good fitting based on the experimental data was carried out. • Sensitivities, including reservoir heterogeneity and operation parameters, were studied by numerical simulation method. • Results show that VR-SAGD presents good potential in improving post-SAGD performance and reducing steam consumption. [ABSTRACT FROM AUTHOR]

The steam oil ratio (SOR) usually increases during the later steam-assisted gravity drainage (SAGD) process, resulting in a decrease in economic benefits and an increase of oil remaining in the wedge zones. To extract wedge zone oil efficiently and economically, this study proposed a method, namely infill wells assisted in-situ combustion (ISC) following SAGD, which takes advantages of SAGD and ISC in sequence by proper well patterns. The requirements for successful ISC following SAGD were discussed, including fuel supply, thermal communication, high temperature oxidation (HTO) kinetics, and the proper time to convert to ISC and the proper well patterns for ISC. The potential method was studied systematically by both physical and numerical simulations based on parameters of a typical extra-heavy oil reservoir in China. The results show that SAGD can be converted to ISC when the steam chamber extends to the edge of SAGD well pattern with infill wells in the middle of well pair as air injectors. It is shown that infill wells assisted ISC following SAGD method has great potential for enhancing oil recovery in extra-heavy oil reservoirs and also presents good economic benefit and operability due to its high oil efficiency. With the well pattern recommended, the oil recovery and economic benefit can be improved by 12.8% and 26.4%, respectively, compared to continued SAGD process. This will provide important guidance for the development in extra-heavy oil reservoirs worldwide. [ABSTRACT FROM AUTHOR]

In fractured-caved carbonate oil reservoirs with well-developed dissolved caves, most of the caves are generally connected by large fractures to form separate and independent fractured-caved systems. The oil well basically intersects some fractures, and fractures connect one or two large-scale dissolved caves in series or parallel model to form an independent fractured-caved unit. Moreover, due to the large size of the dissolved cave in the fractured-caved unit, it no longer follows Darcy's law, but shows features belongs to pipe flow, free flow or a seepage-pipe flow. In this case, the conventional equivalent multiple porous media seepage mathematical model is inaccurate to characterize this kind of fractured-caved reservoir units. This study simplifies the structure of the large bead-shaped fractured-caved reservoir and shows how the well-cave and cave-cave units are connected through fractures. Results show that the connected fracture flow exsits in the periphery of the large cave dissolved caves in the area far from wells. Thus either a linear series or a parallel mathematical model is applied to simulate the connection of the two dissolved caves. The fluid flow in fractures is still considered as seepage flow, while in large dissolved caves it is considered as free flow. Therefore, the dual-cave dual-fracture series mathematical model and dual-cave single-fracture parallel mathematical model considering seepage-free flow coupling are established. Laplace transform is then used to mathematically solve the model, and Stehfest numerical inversion is conducted to draw the typical rate transient analysis curves. Finally, sensitivity analysis is applied to discuss the relationship between controling factors of the flow and actual reservoirs. Based on the rate transient analysis type curves, geometric parameters such as radius of cave, permeability and length of the large-scale fracture and dynamic reserves can be obtained. Finally, a field case in a bead-string fractured-caved reservoir unit of Tarim basin is implemented to verify the effectiveness of the proposed models and methods. The parameters obtained by type curve match support exploitation of fractured-caved reservoirs. • The large bead-shaped fractured-caved reservoirs are simplified based on reservoir static carving. • The fluid flow is considered as free flow in large dissolved caves. • The dual-cave dual-fracture series and dual-cave single-fracture parallel mathematical models are established and solved. • Sensitivity analysis is applied to discuss the relationship of the reservoir parameters. • The specific processes of type curves matching have been given in detail. [ABSTRACT FROM AUTHOR]

Steam injection is the most popular used method in recovering heavy oil reservoirs. Many researchers were engaged in enhancing oil recovery (EOR) methods by using various well configurations. Laboratory experiments and field applications have verified the feasibility of extra-heavy oil recovery by steam injection using vertical injector -horizontal producer. It was also referred to as a steam assisted gravity drainage (SAGD) process. However, the characteristic of steam chamber growth and production performance during the vertical injector-horizontal producer steam injection process have not been fully understood. In this study, a 3D physical model was constructed to investigate the mechanisms of the steam injection process using vertical injector-horizonal producer. Numerical simulations were also conducted to verify the laboratory experiment and field application. In the aspect of steam chamber growth, the results revealed that three stages were included during the steam injection process. In the aspect of developing mechanisms, it can be divided into steam flooding and gravity drainage stages. Moreover, the results show that about 43.9% of original oil in place (OOIP) was produced in the gravity drainage stage. In addition, subcool showed significant difference in steam flooding and gravity drainage stages. The temperature distribution mode of the horizontal producer was analyzed and proved to be a significant factor that influences the production performance. Sensitivity analysis by using numerical simulation demonstrated that oil viscosity is the dominant factor that impact the production performance. The results guided the development of pilot test area in Xinjiang Oilfield, China. The study can provide a clearer understanding of the vertical injector-horizontal producer steam injection process in recovering heavy oil reservoirs. • The vertical injector- horizontal producer steam injection process was divided into three stages. • The dominant driving forces, steam flooding and gravity drainage, varies in different developing stages. • Production performance at different developing stages were analyzed, and most oil was developed by gravity drainage. • The results were used to guide the development of the pilot test area in Xinjiang Oilfield. [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 assisted gravity drainage (SAGD) is an effective in situ oil recovery technology in developing extra-heavy oil reservoirs. Large volumes of steam are needed, however, to heat the extra-heavy oil because of its high viscosity. Steam generation consumes large amounts of natural gas, which adversely affects the economics of SAGD, especially when oil prices are low. Moreover, environmental concerns arise because of excessive freshwater use and greenhouse gas emissions from the burning of the fossil fuels to generate steam. Considering these limitations and concerns, this paper evaluates the effectiveness of different viscosity reducers to decrease the steam consumption and improve SAGD performance. We conducted a series of screening experiments, including viscosity-reduction ratio, thermal stability, and core flooding, for nine types of viscosity reducers, based on an extra-heavy oil sample from a commercial SAGD project in China. The results indicate that water-soluble viscosity reducer #8, a nanoemulsion, is suitable for SAGD. It has a viscosity-reduction ratio of 98.0% at 50 °C and is still effective after high-temperature and high-pressure (200 °C, 4.0 MPa) treatment, with a viscosity-reduction ratio of 92.6%. The displacement efficiency is improved by 29.1%, and the cumulative steam-to-oil-ratio is reduced by 45.3% compared with pure steam flooding. Despite viscosity-reduction, the effect of interfacial tension reduction plays an important role in improving displacement efficiency during the coinjection of steam and viscosity reducer #8 has good potential to improve SAGD performance in developing extra-heavy oil 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]

• The super-heavy oil reservoir with interlayers were classified quantitatively by geological and producing parameters. • New way was given for evaluating the development effects of SAGD during the mid-later stages in super heavy oil reservoirs. • Fuzzy comprehensive evaluation method and analytic hierarchy processes were introduced firstly to the evaluating processes. • New standards the ranking of five producing parameters were determinated based on influences for developments effects. The problems of energy consumption and decreasing production are prominent during the middle and later stages of steam-assisted gravity drainage (SAGD) in super-heavy oil reservoirs. Geological parameters and production parameters have an important impact on the development effects. However, there is no quantitative method to evaluate production effects of SAGD during the middle and later stages. In order to fill this gap, this study proposed a new approach to quantitatively evaluate the development effects of SAGD by considering the geological and production parameters for super-heavy reservoirs. Where, the primary factors controlling reservoir's characteristics and development effects of SAGD were determined by using numerical simulation method. There are 42 well pairs that have already entered the middle and later stages using SAGD in the Xinjiang oil field, China, which were taken as an example. Firstly, a fuzzy cluster analysis model was established to classify reservoir by considering three geological indicators. The results indicated the potential of production for each well pair. Then a fuzzy comprehensive evaluation model was established to evaluate development effects by considering five production indicators. The new standards and ranking of evaluation indicators were quantitatively confirmed by using analytic hierarchy processes. Finally, the approach combined reservoirs classification and development effects evaluation to provide a quantitative and comprehensive evaluation of each well pair. The oil recovery ratio and utilization degree of the horizontal section can clearly reflect the development effects according to comprehensive evaluation results, which means that when the well group meets the recovery factor less than 3.0% and the utilization degree of horizontal section less than 85.0%, the development effects are evaluated as "Category III". Based on the evaluation results, the corresponding follow-up adjustment measures can be adopted. This study has guidance on the development of technical countermeasures for different types of well pairs. [ABSTRACT FROM AUTHOR]

An analytical model to predict the steam oil ratio (SOR) of the steam-assisted gravity drainage (SAGD) process, including the growing up, expanding and depletion of the steam chamber development, is proposed through the use of steam chamber development modes, energy balance, and mass balance. The calculated instantaneous steam oil ratio (ISOR) and cumulative steam oil ratio (ISOR) using the new analytical model are compared and validated with other analytical models results and numerical simulation results. The results showed that the new analytical model can predict the changing of SOR during the lifetime of the SAGD process more accurately than other analytical models. In addition, it had a high agreement with the numerical simulation results. Additionally, the new model could predict more parameters, including water cut, steam quality, heat proportion in different parts of a reservoir than previous models. This model could be a fast-effective guide for the design, prediction, and adjustment of field dual-horizontal SAGD well pairs. • A new analytical steam oil ratio prediction model for the lifetime SAGD process was proposed. • Key producing parameters and the heat proportion for different parts were considered and were predicted using this new model. • The new model was considered the heat distribution ahead of steam chamber, resulting in more accurate prediction results. • The applying results of the validations certified the reliability and accurateness of the new model. [ABSTRACT FROM AUTHOR]

The distribution of the remaining oil in developed oilfields is primarily influenced by the existing diagenetic reservoir facies (DRFs), which encompass the effects of both the sedimentary environment and the local diagenetic processes on the reservoir quality. We divided the Lower Karamay Formation reservoir samples into nine DRFs according to characteristics such as porosity, permeability, diagenetic intensity, and rock type. After applying the sequential indicator simulation methodology, we were able to create three-dimensional (3D) geological models of the DRFs. Based on these models, we can see that, during phases A and B of eodiagenesis, the prevailing DRF is a sandstone/sandy conglomerate that is moderately to weakly dissolved, moderately cemented, and characterized by moderate porosity and permeability values. The highest quality DRF, which emerged during the early stage of mesodiagenesis, is a sandstone/sandy conglomerate that is weakly compacted/cemented, moderately-to-strongly dissolved, and characterized by very high porosity and permeability values. By providing high-quality analyses of the DRFs in Block 6 of the Karamay oilfield, we provided vital information that allowed the operation to more efficiently target and extract oil from reservoir units that are already in production. • Alluvial fan reservoirs were classified into 9 diagenetic reservoir facies (DRFs) by petrologic and petrophysical features. • Based on coupled relationships among petrologic features and well logging responses, the DRFs of all wells were identified. • DRFs with low porosity & low permeability sandstone/conglomerate accounting for 71.1% are dominant in 3D models of DRFs. • Reservoir architecture, rock type and diagenesis intensity are the major controls on the evolution of DRF. [ABSTRACT FROM AUTHOR]