CO2 huff-n-puff in tight oil reservoirs can enhance oil recovery and store CO2. The existing researches on CO2 huff-n-puff flooding and CO2 storage in tight oil reservoirs rarely take parameters related to CO2 storage capacity as evaluation indicators. Taking typical tight reservoirs in the seventh member of Yanchang formation (Chang 7 member) in the Ordos basin as an example, through numerical simulation, six injection-production parameters (huff-n-puff timing, injection rate, injection time, soaking time, production time and huff-n-puff cycle) and three evaluation indicators (oil exchange rate, CO2 retention coefficient, and flooding-storage synthesis coefficient) were selected. Using single-factor control variable method and multi-factor orthogonal experimental design, together with range analysis method, the sensitivities of the six injection-production parameters to three evaluation indicators were analyzed. The results suggest that in the CO2 flooding-dominant stage, it is recommended to set an injection time of 30-60 d, injection rate of 0.001 0-0.003 0 PV/d, and huff-n-puff timing of less than 0.5 a; in the CO2 storage-dominant stage, it is recommended to set a production time of 30-230 d, injection rate of 0.007 5-0.010 0 PV/d, and injection time of 145-180 d; and in the synergistic optimization stage of CO2 flooding and storage, it is recommended to set an injection time of 30-65 d, huff-n-puff timing of 6 months earlier, and soaking time of 10-20 d.
Due to the low oil recovery percent of reserves, developed barriers/interlayers, and difficult remaining oil prediction in the heavy oil reservoirs in the Panyu oilfield group, it is urgent to improve the accuracy of reservoir architecture analysis and prediction. Based on geological, seismic and logging data, together with GR return rate and big data statistical technologies, the 3rd-, 4th-, and 5th-order architecture boundaries in the reservoirs were identified, the distribution patterns of interlayers were studied, the internal structure of reservoir architecture units and the distribution of interlayers were quantitatively characterized, the main controlling factors and occurrence patterns of the remaining oil were analyzed, and the control of architecture boundary on remaining oil was clarified. The results show that the 3rd-order oblique progradational interlayers in the reservoirs can slow down vertical fluid flow, and the 4th-order superimposed horizontal interlayers can prevent vertical fluid channeling. The energy and direction of remaining oil migration are mainly constrained by the 3rd- and 4th-order interlayers and the rhythm differences. Ten ineffective and inefficient wells were sidetracked, which revealed an initial cumulative oil production of 680.00 m3/d, five times that before sidetracking.
During the development of multi-layer heterogeneous reservoirs through commingled injection and production, interference between layers occurs due to various factors such as reservoir lithology, petrophysical properties, formation pressure, and fluid properties. The previous laboratory experiments on parallel displacement failed to effectively simulate fluid exchange between layers during the commingled production of multiple layers, and the physical meaning of the defined interference coefficient does not align with the flow process in water injection development. In this paper, an experimental model of series-parallel combined displacement was established to simulate the variation of lithology within the reservoir layers. The oil production, water cut, and recovery rate of cores with different permeabilities in the experiments were investigated to verify and re-understand the interference coefficient. The results show that interlayer interference is essentially a phenomenon that the variation of flow resistance of reservoir layers with time leads to alteration in flow distribution within the layers. Reservoir heterogeneity is identified as a key factor in forming dominant flow channels during commingled production. The research results provide a reference for designing interlayer interference experiments and developing heterogeneous reservoirs rationally and efficiently.
The oil-water relationship of the heavy oil reservoir in the first member of the Neogene Shawan formation （Sha 1 member） in Chunfeng oilfield is complex and cannot be explained from the traditional viewpoint of oil-water contact （OWC）, which affects the exploration and development process of the oilfield. Taking the P601-20 block with prominent contradiction in oil-water relationship as an example, researches on seismic-geology and pool-forming dynamics were conducted, and combining with the reservoir performance during development, the oil-water relationship of the heavy oil reservoir in Sha 1 member and its genesis were analyzed. It is found that the complex oil-water relationship in this oilfield is caused by the presence of a tilted OWC in the reservoir which is a structural-lithological reservoir with bottom/edge water. In terms of reservoir physical property, fault, formation pressure, tectonic movement, etc., the presence of the tilted OWC should be attributed to the adjustment of the reservoir due to tectonic movements, and the crude oil densification and flat strata intensified the lag of OWC adjustment. This reservoir can be classified as an unsteady oil and gas reservoir.
In order to determine the oil-water contact in the eastern transitional zone of the Daqing SN oilfield, based on the drilling, logging, and seismic data, together with the core oil occurrence analysis and the reinterpretation of oil/water layers in existing wells, a comprehensive method for determining the oil-water boundary in the extension zone of structural reservoirs was discussed by using the techniques such as hydrocarbon detection through post-stack seismic attributes based on dual-phase medium theories and fluid identification based on pre-stack seismic waveform indication inversion. The oil-water interface in the study area exhibits the following characteristics: (1) oil patch or higher level occurs in cores; (2) oil layers or oil-water layers are extrapolated on the basis of logging interpretation; (3) in post-stack attributes, the energy ratio of low frequency to high frequency is greater than 0.85; and (4) the predicted water saturation from pre-stack inversion is less than 75%. Therefore, following the principle of “depth of oil-water contact determined by well data, boundaries of oil and water distribution determined by seismic data, and validation by well performance”, and through comprehensive analysis from point to line, plane, and then space, the final position of the oil-water interface was determined. The research results effectively guide the extention deployment and evaluation in the study area, and are referential for delineating the oil-water boundaries in similar structural reservoirs.
It is necessary to improve development efficiency of heavy oil reservoirs in the late stage of steam flooding. In this paper, considering the application of the technology of carbon capture, utilization and storage, and enhanced oil recovery （CCUS-EOR）, and taking the J6 block of Karamay oilfield as an example, four components of heavy oil were analyzed before and after CO2 treatment, and the changes in saturation pressure, expansion coefficient, viscosity, and density were tested to investigate the regulation of CO2 on physical properties of heavy oil. Parallel core physical simulation experiments were performed to understand the performance of CO2-assisted steam flooding in improving oil recovery. The results show that the viscosity of heavy oil is mainly affected by the contents of resin and asphaltene. As the volume of CO2 dissolved in heavy oil increases, the saturation pressure rises from 2.08 MPa to 11.11 MPa, and the expansion coefficient shows an upward trend, with an increase of 7.6%; meanwhile, the viscosity and density of the heavy oil decrease by 30.5% and 3.5%, respectively. This indicates that CO2 can effectively improve the physical properties of heavy oil by optimizing the expansion coefficient, viscosity, and density while increasing the saturation pressure. In addition, the application of CO2-assisted steam flooding enables the recovery of heavy oil to increase from 38.55% to 46.46% under the effect of CO2 dissolution for viscosity reduction and demulsification, representing an increase of 7.91% compared to pure steam flooding. This study provides a theoretical and experimental basis for the application of CO2-assisted steam flooding in enhancing the recovery of heavy oil, offering insights for similar heavy oil reservoirs.
Influenced by crude oil properties, water flooding with self-emulsification in heavy oil reservoirs is different from conventional water flooding, and the conventional theories for light oil water flooding are not applicable to heavy oil reservoirs. Taking a heavy oil reservoir with self-emulsification water flooding and the reservoir fluid parameters in China as cases, the water flooding with heavy oil self-emulsification was studied through laboratory experiments and numerical simulations to clarify key mechanisms and main influencing factors. The new numerical simulation method reveals that the stable displacement stage of the self-emulsification water flooding is a quasi-piston oil displacement pattern. The development process can be divided into four stages, namely pure oil, transition, plateau and rapid WOR increase. Permeability ratio and crude oil viscosity are the main factors affecting the water cut in self-emulsification water flooding, followed by permeability and water injection rate.
Based on the Type Ⅱ generalized water drive characteristic curve，the concept of underground gas-water cut was introduced，and the Type Ⅱ generalized gas-water miscible flooding characteristic curve was established on the basis of analogy. The mathematical model of gas-water cut corresponding to the Type Ⅱ generalized gas-water miscible flooding characteristic curve can be transformed to describe the S-shaped gas-water cut variation and also the convex，S-convex，S-concave，concave，and other shapes of gas-water cut variations，when the characteristic values n and m take different values. This provides additional methods for evaluating development effects of gas-water miscible flooding. The paper put forward a general formula for the Type Ⅱ gas-water miscible flooding characteristic curve and corresponding methods for solving the mathematical model of gas-water cut，and evaluated the development effects of the water-alternating-gas miscible flooding in the reservoir of Sanjianfang formation in Pubei oilfield and the gas cap + edge water miscible flooding in S31 reservoir in Jinzhou oilfield，respectively，showing a high fitting accuracy. This work provides a valuable reference for developing other oil reservoirs.
For continental reservoirs with strong heterogeneity，long-term water injection may create dominant flowing channels，which will cause rapid water breakthrough in oil wells，thereby reducing the displacement efficiency and resulting in poor development results. Taking the Paleogene Oligocene Shahejie formation of Liuzan oilfield as an example，the litho-electric logging responses，reservoir heterogeneity，injection-production performance，and reservoir pore characteristics were analyzed，the characteristics of dominant flowing channels in the multi-layer sandstone reservoirs of the oilfield were described，and the conditions for the formation of dominant flowing channels in this area were determined. A calculation method for the throat volume of dominant flowing channels was established. With this method，the amount of profile control agent used in the subsequent operations was clarified to effectively plug the channels. The research results provide a technical support for subsequent oil production stabilization and water control in oilfields.
The fault-karst reservoirs in the southern Tuoputai block of the Tahe oilfield exhibit a high initial production capacity，but a sharply declining production in the late development stage due to serious water flood and rapid water breakthrough occurred in many wells. There is no efficient simulation method for this phenomenon. Based on the karst features，seismic characteristics，actual well-reservoir configuration，and three-zone structure of fault-karst reservoirs，a grid-like fragmented structure of the fault-karst reservoirs was proposed. Accordingly，by combining the automatic fault extraction (AFE) technology with the ant body attributes，the fracture indicator was derived for characterizing the grid-like fragmented reservoir. Tensor attributes were used for characterizing the karst-vug reservoir，and a dual-porosity compositional model was established for numerical simulation. The results indicate that the grid-like fragmented structure serves as the primary flow channel in fault-karst reservoirs. The fracture indicator is better applicable to characterize the grid-like fragmented structure than AFE and maximum likelihood，and it is highly compatible with tensor attributes in water source zone but poorly compatible in other areas. Compared to single-porosity model，the dual-porosity model based on the grid-like fragmented structure can offer higher matching accuracy and better reflect the production performance of the fault-karst reservoirs.
This paper presents the characteristics and development history of the multi-layered sandstone heavy oil reservoirs in the Kern River field，USA，and specifically discusses the practices of thermally recovered reservoir management and enhanced oil recovery (EOR). The Kern River field is a monocline reservoir of hydrodynamic trap. In the late stage of steam flooding，the practices such as C/O spectral logging，4D time-lapse dynamic surveillance during thermal recovery，injector-producer performance monitoring，isolated single-channel sandbody identification and tracking，and full-field 3D geological modeling and numerical simulation lay a basis for identifying remaining oil and enhancing oil recovery. Artificial intelligence，steam-foam flooding，and layered steam injection through dual-tubing completion are proved technologies for expanding the swept volume of steam flooding. Infill drilling，horizontal well drilling，and horizontal sidetracking in shallow oil reservoirs provide additional opportunities for significantly increasing the recoverable reserves. These technologies enable the production of horizontal well to be more than three times that of adjacent vertical wells. To exploit “cold reservoirs” near the oil-water contact in the downdip zone of the reservoir，water producers are drilled in the downdip aquifer zone to release reservoir pressure，allowing the remaining oil in this zone to be effectively swept by steam.
The side-view images of microseismic monitoring in horizontal wells in the shale reservoirs in the Jimsar sag of Junggar basin and in the southern Sichuan basin exhibit a phenomenon that the density and extent of the data points parallel to bedding direction are much greater than those perpendicular to the bedding direction. This phenomenon contradicts the hydraulic fracture interpretation results from conventional processing. However，there is no clear explanation for this phenomenon in terms of 3D geometry of hydraulic fractures. A method of microseismic inversion was established，and the inversion results were reconstructed to obtain 3D geometry of the fractures induced by horizontal well hydraulic fracturing in shale reservoirs. Finally，the fracture geometry and the microseismic inversion method were verified through physical simulation experiments on fracturing under true triaxial stress. The results show that the fractures from inversion primarily exhibit a geometrical pattern of one main fracture intersecting with multiple secondary fractures in three dimensional space. Combining with the results of fracturing physical simulation experiments under true triaxial stress，it is found that the hydraulic fractures are horizontally and vertically intersected. The results of acoustic emission experiments and the fracture geometry presented after true-triaxial fracturing physical simulation of outcrop samples from the Jimsar sag validate that the microseismic inversion method is reliable and the fractures induced by horizontal well hydraulic fracturing in shale reservoirs are complex.
The tight sandstone gas reservoirs in the Linxing gas field，Ordos basin，are key targets for onshore gas development. Due to the structural complexity，reservoir physical properties，and complicated gas-water relationship，most gas wells produce water continuously after fracturing，and their water production rates are very different. Understanding the reasons for irreducible water saturation variation after fracturing is of great significance for formulating effective water control and gas recovery measures to increase well productivity. In this study，representative tight sandstone samples from the Linxing gas field were tested by using the gas displacement method to clarify how reservoir properties，production pressure difference，and fracturing fluid affect irreducible water saturation. The results show that the difference in the irreducible water saturation between matrix and fractures is 13.32%~18.36% for Class Ⅰ reservoirs，28.28%~34.19% for Class Ⅱ reservoirs，and 39.10%~48.15% for Class Ⅲ reservoirs. Hydraulic fractures can significantly improve the water flow capacity of reservoirs，and provide additional water flow pathways. The increased production pressure difference，reduced flow pressure loss and weakened hydrophilic degree are the main mechanisms leading to the weakening capacity of the reservoir in bounding water and water production of gas wells after fracturing. To control water and produce gas efficiently in tight sandstone gas reservoirs with high water cut after fracturing，measures such as controlling fracturing scale，optimizing production systems，and adjusting fracturing additive amount can be implemented，which will help delay the onset of water breakthrough in gas wells and reduce the overall water production.
The development of the reservoirs with narrow oil ring, gas cap, and bottom water is often challenged by water coning, gas channeling, and complex remaining oil distribution. This paper discusses the well location optimization and potential tapping strategy for horizontal well development in the Bohai Bay basin. In the basic well pattern arrangement stage, in plane, horizontal wells are arranged perpendicular to the structural lines and penetrating multiple layers for enhancing the recovery of reserves, and the separated-layer production string with intelligent sliding sleeve is equipped to alleviate inter-layer contradiction; vertically, horizontal wells are arranged parallel to the fluid interface and at 1/3 of the oil column height from the water-oil contact for gas channeling prevention and water control. In the comprehensive adjustment stage, according to the numerical reservoir simulation, the remaining oil is enriched in inter-well retention zone in plane in the middle-late development stage, and is vertically enriched in the upper part of the reservoir due to the subsequent dominance of water drive in the late stage. Comparing the oil increment indexes under the schemes of inter-well sidetracking, gas reinjection into the gas cap, and barrier water injection, the former two schemes are preferred for tapping the potential remaining oil. Ineffective and inefficient wells are sidetracked to the zones at high positions between wells, with the expected net oil increment of 3.4×104-4.2×104 m3 per well. For gas reinjection into the gas cap, existing gas production wells are converted for gas reinjection to replenish the energy of the gas cap, so as to displace the remaining oil in the upper part of horizontal wells and enhancing the oil recovery, with the expected net oil increment of 5.2×104 m3 per well.
In order to clarify the controls of barriers/interlayers on the distribution of remaining oil in the braided-river reservoirs，taking the sand set Ⅱ in the third member of the Guantao formation （N1gⅡ3） in the Liuguanzhuang area of Dagang oilfield as an example，and using the data of core，testing，logging，and production performance，the criteria for quantitative identification of barriers/interlayers were established for the target interval in the study area，and the hierarchy，genesis of barriers/interlayers and their controls on remaining oil distribution were determined. In the study area，the barriers/interlayers in the target interval can be divided into 3 categories such as barriers between sand sets，interlayers between sand bodies，and interlayers within a sand body，which are developed near the architecture boundaries of the 7th-，8th-，and 9th-order sand bodies，respectively. The barriers between sand sets are dominated by floodplain mudstones and silty mudstone，with the thickness ranging from tens of centimeters to several meters. They can efficiently seal oil and gas vertically and allow the edge water to advance preferentially along the formation during development，leading to severe water flooding，and thus the remaining oil is mostly distributed in the upper parts of the complex mid-channel bars and braided channels far from water injection wells. The interlayers between sand bodies are mainly composed of fine-grained sediments in abandoned channels and gullies，with the thickness typically ranging from 0 to 2 meters. They locally hinder vertical fluid migration and laterally control the distribution of remaining oil in different sand bodies，leading to two remaining oil distribution patterns：one is controlled by abandoned channel and the other by gully. The interlayers within a sand body are primarily associated with lateral accreted and interchannel mud deposits，and fall-silt seam，with the thickness reaching tens of centimeters，leading to three remaining oil distribution patterns，which are controlled by laterally-accreted mudstone，fall-silt seam，and interchannel mudstone，respectively.
Fluid flow in the reservoir is no longer merely linear or radial after fracturing, instead, the flow field becomes complex and cannot be directly solved using analytical methods. In order to derive a production formula for fractured vertical wells, the complex flow field in the reservoir was decomposed into three simple flow patterns: outer radial flow, middle linear flow, and fracture linear flow. Each of these flow patterns was separately solved, and by applying the principles of fluid-electric similarity and equivalent flow resistance method, a production formula for fractured vertical wells was analytically derived. This formula can be used to calculate and predict the production of fractured vertical wells, and also to determine the fracture length and fracturing effect.
Remaining oil aggregation is a key indicator for evaluating the recovery effect and potential of high water-cut reservoirs. In this study, the dominant reserves zones within the reservoir are determined based on remaining reserves abundance. The weights of indicators are determined with the entropy weight method by using block area, distribution density and shape index. Finally, the remaining oil aggregation is characterized. The results show that, for a reservoir under steady development, the dispersion and accumulation of remaining oil can be divided into four stages: primary dispersion, rapid separation, fluctuating accumulation and dispersion, and secondary dispersion. Utilizing these characterization indicators, an evaluation was conducted on the Nm3-4-1 layer in No.7 fault block in Block 2 of the East Dagang Development Area, Dagang oilfield. The results show that the remaining oil aggregation in Nm3-4-1 decreased steadily with the progress of development, and it starts to rise owing to injection-production structure and well pattern adjustments.
The wells drilled in the fault-karst condensate gas reservoirs in Shunbei oil and gas field of Tarim basin exhibits significant formation pressure fluctuations, making conventional well testing interpretation methods based on constant formation pressure inapplicable. Additionally, due to the presence of water and high contents of condensate oil in gas wells, the evaluation results of open flow rates of the wells deviate significantly. Based on systematic well testing data that are corrected with elastic productivity in the well testing stage, this paper presents a productivity evaluation method for the condensate gas wells with water and high content of condensate oil. The field application validates that this evaluation method is applicable for assessing the open flow rate of condensate gas wells in the Shunbei oil and gas field to provide a quantitative understanding on the productivity of condensate gas wells with water and high content of condensate oil in Shunbei area.
The geological and development characteristics of ultra-deep fault-controlled fractured-vuggy reservoirs in Shunbei oilfield were comprehensively analyzed, and insufficient natural energy was determined to be the main reason for the rapid production decline and formation oil degassing in the weakly volatile oil reservoirs in the Shunbei No.1 fault zone. Through numerical simulation, it is clarified that water injection is the optimal development method currently. The research results show that gravity differentiation is the main mechanism of water injection in the ultra-deep fault-controlled fractured-vuggy reservoirs in Shunbei oilfield, and water injection can effectively restore formation energy. The waterflooding connectivity and energy balance capability in the fault zone’s pull-apart segments are much stronger than those in the compression segments. Water injection development of the ultra-deep fault-controlled fractured-vuggy reservoirs features rapid water channeling along fault zone and small swept area. Water injection enables good development effect, with the reservoir pressure restored by 14.78 MPa averagely, the annual decline rate of the block decreasing from 48.6% to 15.9%, and the staged cumulative oil production increased by 13.10×104 tons.
Based on the discrete fractured-vuggy reservoir model, an oil-water two-phase flow model and a numerical simulation method considering matrix-fracture flow and vug free flow were established to analyze the performance of one-hole multi-target staged fracturing in fractured-vuggy reservoirs, and the impacts of natural fracture development degree, bottom water, and number of fracturing clusters on the fracturing performance were identified. The results show that, in the absence of bottom water, the natural fracture development degree only affects production rate but has a minor impact on the ultimate oil recovery; and in the presence of bottom water, the bottom water rising along natural fractures displaces the crude oil in cavities, leading to an increase in oil production with the increase of natural fracture density. Vug size and hydraulic fractures significantly affect the productivity of fractured-vuggy reservoirs. When natural fractures are highly developed, the difference between the performance of fracturing by single cluster in one stage and by multiple clusters in one stage decreases significantly, indicating that a single cluster hydraulic fracture can effectively control the entire sweet spot area in the fractured-vuggy reservoir.
