With self-emulsification function, the heavy oil reservoir in Wellblock Ji-7 is different from light oil reservoirs and conventional heavy oil reservoirs in waterflooding behaviors at normal temperature, and the waterflooding efficiency is higher in the reservoir. After analyzing the cause of the self-emulsification and the characteristics of emulsion in Wellblock Ji-7, the waterflooding behaviors are defined and it is considered that the main reason for a long-term steady water cut in the middle water-cut period in Wellblock Ji-7 is that the water-to-oil ratio is close to 1 due to the self-emulsification of water-in-oil emulsion. It is further proposed that stabilizing the water-to-oil ratio is one of the most effective measures for waterflooding development in heavy oil reservoirs, and keeping the water-to-oil ratio around 1 can maximize the recovery of heavy oil reservoirs.
CO2 can increase formation energy and reduce oil viscosity. Asynchronous CO2 huff and puff is becoming one of the effective methods for improving the recovery of tight oil reservoirs. The interaction among injection, production and soaking processes can significantly increase inter-well reserves producing degree, and this technology is expected to become an option for enhancing the oil recovery of the Mahu tight conglomerate reservoirs in the Junggar basin. According to the formation pressure, saturation pressure and minimum miscible pressure, an asynchronous CO2 huff and puff experiment with two cores in parallel was designed for clarifying the influence of reservoir physical properties, injection-production pressure difference and huff-puff timing on development effect. The results show that the crude oil recovery after asynchronous CO2 huff and puff is about 3-5 times higher than that of the depletion development; the better the physical properties of the reservoir, the smaller the flow resistance, and the more favorable for asynchronous CO2 huff and puff to improve oil recovery; the greater the injection-production pressure difference, the more significant the inter-well pressure change, and the more crude oil is produced; when the gas injection pressure is greater than the miscible pressure, it is beneficial for supercritical CO2 to play the role and to improve the recovery; when the formation pressure is higher than the miscible pressure, it is necessary to increase the pressure of the gas injection well and reduce the pressure of the adjacent production well through asynchronous CO2 huff and puff to increase the pressure difference of the injection-production system, expand the swept volume, and improve the inter-well reserves producing degree.
Injection and production of a UGS (underground gas storage) with edge and bottom water is likely forcing gas-water contact to move, so it is necessary to assess the migration of water invasion front and the injection-production risk since it is very important for recovering the storage capacity and improving the peak shaving ability of injection and production wells. Taking the Hutubi UGS as a case, we evaluated the feasibility of recovering the gas/water front of the UGS with edge and bottom water, simulated the position of gas front by tracer numerical simulation technology, and enhanced the flow capacity of the reservoir by multiple cycles of gas flooding. Then an indicator system evaluating dynamic and static parameters that affect the water invasion in injection and production wells was established, and the risks of water breakthrough were evaluated in 30 injection and production wells in Hutubi UGS. It is found that there are only 3 wells with high water invasion risk in the study area, which are located in the western water invasion area. Finally, an early water invasion warning mechanism was proposed. The mechanism aims to monitor the production performance, record real-time production parameters such as water production, water-gas ratio, Cl- content in produced water and wellhead pressure of the wells with medium–high water invasion risks, and adjust and optimize the injection and production rates and gas volumes, and as a result, control the advancing speed of the gas/water front.
In order to describe the microscopic distribution of remaining oil in high water-cut reservoirs during the late development stage, and guide subsequent fine development of remaining oil in blocks Xiaoji and Gangxi in Dagang oilfield, remaining oil data was observed under an ultraviolet fluorescent stereo microscope and then was processed, and finally the distribution of the remaining oil is divided into three levels, namely, weak sweep, medium sweep and strong sweep, and the occurrence states of the remaining oil are divided into five types, namely, cluster shape, pore-surface film shape, slit shape, corner shape and intergranular adsorption. In the high water-cut stage, the content of the remaining oil in different occurrence state is in the order of cluster, pore-surface film, corner, intergranular adsorption to slit shapes from high to low. After poly/surface compound flooding, remaining oil occurrences like clusters and pore-surface films are dominant. Such remaining oil could be exploited by improving rock wettability. The distribution of remaining oil in conglomerate is more complex than that in sandstone. Remaining oil in sandstone are almost distributed as clusters and intergranular adsorption, which can be exploited by controlling the fluidity of injected fluid.
Fractured-vuggy carbonate reservoirs are difficult to develop efficiently due to their strong heterogeneity, challenging connected unit identification, and unknown inter-well connectivity. In this paper, facies-controlled inversion and maximum likelihood attribute were used to characterize the fractured-vuggy aggregate and spatial distribution of large-scale fractures, so as to identify connected units and clarify the inter-well connection mode and the remaining oil potential. Based on dynamic data of wells, the connectivity was analyzed to verify the rationality of the connectivity characterization result obtained from static data. The technique was applied in the gas injection development of the Lungu 7-5 well group in the Lungu 7 wellblock, providing a basis for gas injection development strategy making to further improve the reservoir recovery performance.
Shale reservoirs of the Permian Lucaogou formation in the Jimsar sag, Junggar basin are highly heterogeneous, so that the production of horizontal wells after volumetric fracturing stimulation declines rapidly. The oil recovery is predicted to be low by depletion development and the properties of the produced oil are very complex. After analyzing the physical properties and occurrence of the crude oil, and the physical properties of the produced fluid, and combining with the producing modes of reserves and the distribution of remaining oil, the physical properties and distribution of the shale oil are characterized in terms of pores, reservoirs and wellbore. The oil in large pores is lighter and uneasily adsorbs to the pore wall, whereas the oil in small pores is heavier and easily adsorbs to the pore wall due to more heavy components in it. The viscosity of the crude oil produced alternatively from the reservoirs with different physical properties has been changing, which can be classified into four types such as unobvious change, slight decrease, significant decrease and slight increase. The crude oil produced from the lower sweet spot interval is heavier and easy to emulsify. The viscosity of the emulsion increases sharply when the water cut is greater than 30%, so the water cut may be the primary cause for the emulsification of the crude oil. CO2 huff and puff may be effective to produce the adsorbed crude oil that cannot be displaced through depletion development. In high water-cut period, injecting surfactants may help reduce the viscosity and elasticity of emulsified crude oil and improve the oil recovery.
The reservoir in the upper Wuerhe formation, southern Block 5, Karamay oilfield, is a heavy oil reservoir with low porosity and low permeability, indicating poor reservoir physical properties. When it was developed by water injection, the production decreased rapidly, and the formation energy kept low; as a result, all production wells were shut in or suspended. In recent years, some wells have been refractured to resume production and good effects have been gained in the initial stage, but the production declines rapidly. In order to solve the problems of low production and low efficiency of production wells, the CO2 + surfactant combination huff and puff technology was developed and tested for production enhancement. On the basis of experiment on stimulation mechanism, through multi-component reservoir numerical simulation, the method and parameters for injecting CO2 + surfactant were optimized. The relationship between the changes of the production increment and the parameters such as injection volume, injection rate, soaking period and production intensity in different cycles of huff and puff were established, and the optimal parameters for injecting CO2 + surfactant were determined for huff and puff. Field application reveals a natural flow of a sing well for 240 days and an incremental oil production of 630 t. It is concluded that the CO2 + surfactant combination huff and puff technology can effectively supplement formation energy and improve fluid mobility, which can be used as a reference for the development of similar reservoirs.
Located in the Neogene Shawan formation in the central Block Pai 601 and southern Block Pai 6 of Chunfeng oilfield, the ultra-heavy oil reservoirs are characterized by shallow burial, thin pays, low original formation pressure and high crude oil viscosity. A compound method integrating horizontal well, viscosity reducer, steam with nitrogen is usually used to develop these reservoirs. After several cycles of huff and puff development, the formation pressure dropped, edge and bottom water broke through the oil-water contact and coned upward, resulting in a longer water drainage period, higher cumulative water production, and a shorter effective production period, and consequently relatively low ultimate oil recovery. Therefore, a steam huff and puff test assisted by nitrogen foam was carried out, and indoor experiments and numerical simulation techniques were used to analyze and compare foam applicability and optimize injection parameters and process. Field test results show that after applying steam huff and puff assisted by nitrogen foam in the blocks with edge and bottom water intrusion, the average water drainage period in the oil well was shortened by 8.3 days, the water cut decreased by 32.2% and the cumulative oil production increased by 2 606.0 t. In the blocks after several cycles of huff and puff, injecting nitrogen foam reduced the water cut by 8.6% and increased the cumulative oil production by 1 668.0 t, indicating that nitrogen foam can effectively increase formation energy, block large pore channels, adjust steam absorption profile and play a key role in improving the ultimate oil recovery.
The low-permeability sandy conglomerate reservoirs of Benbutu oilfield in Yanqi basin was developed by water flooding in the early stage. While along with water flooding, the reservoirs were seriously damaged, it was even harder to inject water into the reservoirs and the recovery rate stayed in a low level, therefore, it is urgent to switch flooding agent to further improve the recovery rate. In order to determine the feasibility of CO2 injection in the low-permeability sandy conglomerate reservoirs in Benbutu oilfield to enhance oil recovery, indoor experimental researches were carried out. The research results show that the crude oil in the formation of the study area has good swellability, is easily miscible with the injected CO2, and the viscosity of the crude oil is easy to be reduced. The minimum miscible pressure of the reservoirs is about 25 MPa, and near-miscible flooding can be achieved under the current formation pressure. The oil displacement efficiency of CO2 flooding is relatively high, which can dramatically improve recovery rate. The CO2 flooding plan was optimized with numerical simulation, in which a five-spot well pattern and a continuous gas injection method were adopted, and the oil recovery is expected to increase by about 13.37% and the oil diplacement ratio of CO2 injection will be about 0.33 t/t. The numerical simulation results provide a theoretical basis for the next field application.
The conglomerate reservoirs in the Mahu sag of Junggar basin are tight and the reservoir fluid has a poor flow capacity, resulting in rapid decline and unsteady production. Although the effect of CO2 pre-pad fracturing is better than that of hydraulic fracturing, no systematic study has been carried out on how CO2 affects the crude oil and reservoir rocks in Mahu sag. In this study, the displacement ability of CO2 aqueous solution, the dissolution of core minerals and the changes in core porosity and permeability are analyzed. It is found that in the Mahu conglomerate reservoirs, the crude oil displacing rate by CO2 aqueous solution is higher than that by pure CO2 or water. The Mahu conglomerate reservoir has a higher carbonate content, so CO2 aqueous solution can play a stronger dissolution role and increase the porosity and permeability of the reservoir. Experimental results show that the porosity has increased by 27% on average, and the permeability has increased by 110% on average. The injected CO2 aqueous solution prefers dissolving calcite first, then dolomite and last chlorite. Mineral dissolution mainly occurs in the first 5 days, and then becomes less after 5 days.
In order to investigate the deep fractured-vuggy reservoir in Tahe oilfield, the minimum miscible pressure of hydrocarbon gas-crude oil system is calculated through indoor phase behavior experiments and using empirical formula method, pseudo-ternary phase diagram method and slim tube simulation method, and the influences of early nitrogen injection and crude oil quality on hydrocarbon gas miscible flooding are studied through numerical simulation. The research results show that the minimum miscible pressure calculated by the three methods is much lower than the average actual reservoir pressure, so hydrocarbon gas-crude oil miscible flooding is very feasible for the deep fractured-vuggy reservoir in the study area; and early nitrogen injection impacts the miscible flooding significantly. In the reservoir swept by injected nitrogen, the minimum hydrocarbon gas-crude oil miscible pressure becomes higher. In the reservoir where the ratio of nitrogen to hydrocarbon gas is greater than 1.208, a miscible phase wouldn’t appear. Crude oil quality also has a great impact on hydrocarbon gas-crude oil miscible flooding. The more the light components in crude oil, the lower the minimum miscible pressure of hydrocarbon gas and crude oil, and the more the heavy components in crude oil, the lower the ultimate recovery rate of the miscible flooding.
The Permian gas reservoirs in the southeastern area of Sulige gas field in the Ordos basin are wet gas reservoirs developed from coal-measure source rocks. No condensate oil is produced just from the reservoir during development. However, when natural gas enters the wellbore and experiences the decreases in both temperature and pressure to below the critical values, condensate oil would appear. In order to increase the production of condensate oil associated with natural gas, the full-component analysis results of natural gas sampling and production data are used to analyze the geological conditions for reservoir forming and the factors such as temperature, pressure and gas production in the process of development. It’s found that the condensate oil production is influenced by the stable balance separation time and the liquid carrying capacity. After analyzing the geological and production conditions, controlling factors on the production of condensate oil are compared, and according to the changes of gas production, the production of condensate oil can be predicted block by block. The result provides basis for updating the gas reservoir development plan in the study area.
For developing the tight conglomerate reservoirs in the Baikouquan formation in Mahu oilfield with small well-spacing, it is urgent to establish an appropriate fracability evaluation model. Based on the optimal parameters such as elastic modulus, Poisson’s ratio and minimum in-situ stress, and combined with the core, logging and seismic data, the 3D geomechanical modeling was carried out for Ma-131 well block. The spatial distribution of the fracability index (0.38-0.91) of the reservoir in the study area was determined. Coupling with the microseismic fracture monitoring and production data from 12 horizontal wells, it is found that the calculated fractability index is consistent with the fracture propagation direction and scale, and the actual production performance of the wells. The research results may provide a basis for developing the conglomerate reservoirs in the study area.
In order to optimize the production system after water breakthrough in the oil wells drilled in ultra-deep fault-karst reservoirs and taking Well Z in Shunbei oilfield in Tarim basin as a case, the characteristics of reservoir geology and water breakthrough in the oil wells were analyzed through reservoir engineering method and numerical simulation. The well productivities before and after water breakthrough were compared, the water invasion rate and producing reserves were calculated, the water channeling characteristics was studied based on numerical simulation and the production system after water breakthrough was optimized. The results show that: 1) The inflow performance curve of Well Z is upturned, because the fluid flows at a higher rate after reducing the bottom hole flowing pressure or increasing the bottom hole producing pressure difference, and new fractures and caves open and more flowable channels occur, resulting in a great increase of the oil productivity in the well; 2) After water breakthrough, the daily oil production dropped sharply, and the productivity reduced dramatically; 3) The producing reserves in Well Z are about 338×104 t, bottom water invaded in January 2020 at a rate of about 0.61×104 m³/month, and by November 3, 2020, the water cone in Well Z was about 395 m from the initial oil-water contact and about 131 m from the bottom hole. According to the results, a 7 mm choke was recommended and used in Well Z. After field application, the daily oil production has increased from 96 t to 170 t and the water cut has been controlled less than 2.00%, indicating a satisfactory result.
Carbonate oil reservoirs are very heterogeneous, so that injected water is easy to advance through high-permeability channels, and results in water channeling or flooding, and consequently fast rising water cut and low development effeciency in production wells. Based on the principle of well connectivity, and considering the geological features and development performance of fractured-vuggy carbonate oil reservoirs, parameters of well connectivity (conductivity and connected volume) were quantitatively characterized, then a vertical multi-layer well connectivity model was established, and parameters such as plane splitting coefficient and utilization rate of injected water were estimated for each layer of the oil reservoirs, and finally by using automatic history matching method and production optimization algorithm, real-time optimization and prediction of production performance of oil and water wells were realized. Field application has proved that the yearly incremental oil production is 1.1×104 m3 by using this method and good effect has been obtained. The method has important guiding significance for efficient development of similar oil reservoirs.
Fractures induced by volume fracturing stimulation to tight conglomerate reservoirs of the Wuerhe formation in Mahu sag are very complex, so that the migration and distribution laws of proppants are not clear, which seriously influences the fracturing effect. Based on 3D reconstruction of fracture shapes and considering the interaction between proppants and rough fracture surface, the influences of gravel size, gravel concentration and width attenuation of the fractures around gravels on proppant migration and distribution were investigated by using a Fluent two-phase flowing model. The results show that gravel size has obvious impacts on proppant migration, and it is negatively correlated to balanced height of proppant bank and positively correlated to balanced time of proppant bank; gravel concentration has weak impacts on proppant migration, and it is negatively correlated to balanced time and balanced height of proppant bank; width attenuation of the fractures around gravels has great influences on proppant migration, and both balanced time and balanced height of proppant bank decrease with the increase of the fracture width attenuation degree around gravels.
In developing the reservoir of the Badaowan formation in Wellblock Ji 7 in Changji oilfield, the results of hydraulic fracturing stimulation in vertical wells are unsatisfactory, and the post-fracturing productivity is limited, so that it is necessary to apply multi-stage fracturing stimulation in horizontal wells. According to the geomechanical characteristics of the reservoir in the Badaowan formation in Wellblock Ji 7, a non-planar artificial fracture propagation model was established using the extended finite element method. By taking into account inter-fracture interference while multiple clusters of fracture propagating simultaneously and the inter-section interference during staged fracturing stimulation, the model characterizes the non-planar fracture propagation in horizontal wells drilled in the Badaowan formation in Wellblock Ji 7. The results show that the inter-fracture interference induced in a section inhibits the half-length of middle fracture clusters, but makes a wider and longer half-length of the fractures on both sides; the inter-fracture interference and the inter-cluster interference make fracture propagation non-planar, and show a certain curvature in geometrical morphology. According to comparative analysis of fracturing data and microseismic data, the modeling results are consistent with the measured data, proving that good application results have been obtained in target zones. A multi-stage fracturing test was carried out in the Badaowan formation in a horizontal well in Wellblock Ji 7. The daily post-fracturing oil production of the horizontal well was 7.8 times that of a vertical well in the same well block, indicating a significant development effect.
Fault-controlled fractured-vuggy reservoirs are extremely heterogeneous and exhibit the diversity and complexity in inter-well connectivity. Clarifying the influence of faults and karsts on reservoirs is conducive to reservoir connectivity analysis and injection-production strategy adjustment. Taking Unit T in the Tuofutai area of Tahe oilfield as an example, the development characteristics of reservoirs were systematically analyzed based on the results of seismic interpretation and the analysis of overlying water system and production performance responses. It was clarified that the reservoir development is mainly controlled by faults and surface water systems. The difference in karstification intensity leads to different characteristics of the reservoirs, which makes development wells show different production behaviors and inter-well connectivities. Based on the analysis of dynamic and static data, an inter-well connectivity model suitable for fault-controlled fractured-vuggy reservoirs was established, which can provide a basis for the adjustment of subsequent treatments.
Compared with conventional oil reservoirs, tight oil reservoirs have poor physical properties and low permeability, and wells drilled in these reservoirs need to be fractured for more production. Due to the geological features and special development techniques, there are many factors affecting the production of these reservoirs, and the simple analogy method commonly used on site for production prediction cannot meet the actual needs. In order to solve this problem, taking the tight oil reservoir in Pingbei oilfield of Ordos basin as the research object and based on the Darcy equation, the main influencing factors for production were quantitatively described through grey theoretical analysis. Moreover, a mathematical model was established by using the multiple regression method, and applied to predict the production of new wells in order to verify the reliability of the model. Production prediction by using the multidisciplinary method that combines the grey theory and multiple regression is more scientific and accurate than by using traditional methods, and it can provide a reference for the development of similar oil reservoirs.
Affected by factors such as reservoir heterogeneity, well interference and pore blockage, the fire front advances unevenly, and results in unsatisfactory fire flooding development of the Block Gao 3618 in Gaosheng heavy oil reservoir of Liaohe oilfield. Therefore, physical experiments on simulating fire flooding process were carried out to understand the temperature limit of crude oil in different oxidation stages, kinetic parameters were revised using the Arrhenius equation, and a well connectivity model was established on the basic well pattern to quantitatively characterize the connectivity between injection and production wells. The rationality of the connectivity model was verified through high-temperature gas tracer simulation. The physical experiments and the model were joined together to characterize the moving trajectory of the fire front, making the fitting accuracy increase to 85%. After optimizing the injection-production parameters based on numerical simulation, the fire front was controlled, gas channeling was slowed down, the fire flooding sweep coefficient was increased and the oil recovery was enhanced. For example, the initial gas injection rate is 10,000 m3/d for Well I5-0151C2 and Well I51-156, and 10,500 m3/d for Well I5-0158C. Supposing that the monthly increase of gas injection is 3,000 m3/d, and horizontal wells produces at a fixed rate of 100 m3/d, the fire front can advance evenly after parameter optimization, the sweep coefficient can increase by 8.74%, and the recovery can increase by 6.37%.
