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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]

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]

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]

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]

The diamond-shape inverted nine-spot well pattern is widely used in developing low-permeability reservoirs with fractures. However, production wells with equal fracture lengths will lead to nonuniform displacement, especially in anisotropic reservoir. Previous researches mainly focused on equal-length fractures, while studies on the unequal-length fractures which can dramatically improve the development efficiency were little. In this paper, a corresponding numerical model with unequal length of fracture designed in the edge and the corner wells was built in a low-permeability anisotropic reservoir. The main objective was to examine and evaluate the effects of anisotropic permeability and fracture parameter on the waterflooding in the diamond-shape inverted nine-spot well pattern. The results indicate that different fractures penetration ratio and anisotropic permeability both result in different development efficiency. Fracture of the edge well are more easily to be water breakthrough, while the increase of penetration ratio of injection well effectively enhance oil recovery. Moreover, the most optimal penetration ratios of production well fractures under different kx : ky are determined. With the increase of kx : ky, the optimized penetration ratio of corner wells fracture decrease, while that of the edge wells increase. Setting unequal length fractures in low-permeability anisotropic reservoirs can effectively improve the oil displacement efficiency in the waterflooding process. [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]

Oil production prediction model and water flooding characteristic curves are generally applied to production performance analysis. However, these two methods have some limitations especially in predicting water cut. Growth model can predict oil production and cumulative oil production, but it cannot predict water cut. Water flooding characteristic curves can predict water cut and cumulative oil production, but it cannot establish the relationship between production indexes and time. The Morgan–Mercer–Flodin (MMF) growth model is a kind of production prediction model. This study analyzed features of MMF growth model, then Hu–Chen (HC) model was deduced on the base of MMF growth model. Theoretical basis of HC model was improved and solution of parameters was simplified. Then combining it with water flooding characteristic curve, a new combined solution model was built. This new combined solution model can predict water cut versus time and it overcame deficiencies of production prediction model and water flooding characteristic curves. The applications of field case selected from the Block-A in Daqing Oilfield indicated that the prediction accuracy of this new combining model can meet the demand of production performance analysis and it can guide the determination and adjustment of the development programs in water flooding hydrocarbon reservoirs. It has features of higher prediction accuracy, easier to use and widely practicable compared with other combined models. [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) 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]

Due to the severe heterogeneity of carbonate reservoirs, the traditional reservoir engineering methods for waterflooding performance forecast, mainly including the material balance equation, waterflooding characteristic curve and production decline curve, suffer from less reliability. The fine-scale reservoir numerical simulation is extremely time-consuming, because petrophysical properties in carbonate geological models change so drastically. To predict the development performance rapidly, a new method for large-scale thick carbonate reservoirs is proposed. By combining the geological characteristics and dynamic performance of each well, vertical stacking pattern of the reservoir are classified, and also good insights into the lateral distribution of typical stacking patterns are also gained. The stacking pattern distributions are further projected onto the waterflooding well pattern, followed by rapid evaluation of production and injection rate of every block. Based on the simulation results for typical stacking pattern blocks, type curves of water flooding on different stacking pattern reservoirs are workout. Then the waterflooding performance for the whole carbonate reservoir is step-by-step quickly predicted at a constant liquid rate so as to keep the reservoir injection-production balance with voidage replacement ratio 1. Finally, a large-scale thick porous carbonate reservoir in the Middle East is taken as an example to show the workflow of the proposed method. The accuracy is further validated by comparing the predicted results from numerical simulation, indicating that the proposed method can save a lot of calculation time while ensuring the accuracy of performance forecast. • A new method for rapid waterflooding performance forecast in large-scale thick carbonate reservoirs is proposed. • The effects of lateral and vertical reservoir heterogeneity on waterflooding performance are considered. • The proposed method can save a lot of calculation time while ensuring the accuracy of performance forecast. [ABSTRACT FROM AUTHOR]