The Chang 7 reservoir in the West 233 area of the Ordos Basin is a typical sandwiched shale oil accumulation with low formation pressure coefficient, rapid production decline, and abundant associated gas. Associated gas flooding experiments were conducted on reservoir rock samples. Combined with NMR T2 spectra, the results of associated gas flooding and huff-n-puff experiments were analyzed, and the huff-n-puff efficiency under varying well spacing was simulated. The results show that the presence of bound water significantly reduces the efficiency of associated gas flooding. After displacement, the signal intensity of pores with T2>10 ms decreases significantly; the displaced oil mainly comes from large pores, while only a small part of oil in small pores is mobilized, leaving a large quantity of residual oil. Associated gas huff-n-puff can effectively improve the recovery of shale oil, with the first cycle contributing most to the recovery, the second cycle witnessing a recovery greater than 85% OOIP, the third cycle recording a recovery not exceeding 15%, and the fourth cycle remaining a recovery basically unchanged. This indicates that the oil in large pores has been mainly mobilized. With the increase of huff-n-puff cycles, the incremental oil production decreases, the oil replacement rate drops, and the increase in recovery factor slows down, gradually entering an inefficient cycle. For associated gas huff-n-puff in horizontal wells with well spacing of 200 m, the optimal associated gas injection time is 639 d, the optimal slug size is 900 m3, the optimal injection rate is 15 m3/d, the optimal shut-in time is 40 d, the optimal injection-production time per cycle is 160 d, and the optimal number of huff-n-puff cycles is 3. The optimal timing for continuous associated gas flooding is 1,200 d, and the optimal associated gas injection rate is 15 m3/d.
To investigate the multi-scale and complex strain-coupled seepage characteristics of coalbed methane (CBM) reservoirs after fracturing, a numerical model for gas reservoirs was established based on finite volume method (FVM). Using the embedded discrete fracture method (EDFM), the fracture system was characterized, coupling with the permeability under matrix creep, desorption swelling, and cleat compression, and considering the nonhomogeneous permeability distribution. The model was validated on production data and then used to identify the influence of hydraulic fracture morphology on the producing degree of CBM reservoirs. The results show that hydraulic fracturing increases the drainage area, enhancing the producing degree and accelerating the overall desorption rate of coal seams. The fracture network formed near the wellbore provides a high-permeability pathway system. Especially in low- to medium-rank coal seams, the ultimate volume fracturing technology significantly increases the production capacity of a single well and prolongs its production period.
Shale volatile oil reservoirs are characterized by small pore throat sizes and complex fluid properties, which compromises the accuracy in predicting reservoir development performance. Conventional prediction methods usually yield the results that are inaccurate or inconsistent with field conditions, since they only take into account a single factor or a few factors. Currently, the main controlling mechanisms in fractured horizontal well development of shale volatile oil reservoirs remain unclear. In this paper, a numerical simulation model based on discrete fracture network (DFN) was built to clarify the influences of multiple mechanisms, including nanopore confinement effect, and spatiotemporal heterogeneity of reservoirs. It is found that the pore throat size controls the development effectiveness mainly by influencing reservoir permeability, and its resulting fluid confinement effect has a relatively small impact on development. The stress-sensitive effect is an adverse factor for the development of shale volatile oil reservoirs. Fractures with high conductivity are conducive to the development of such reservoirs.
After nearly 30 years of waterflooding development, the reservoir in Block WX-3 of Wenmi oilfield has changed in porosity, permeability and microscopic pore structure, resulting in variations of fluid flow behaviors in the reservoir. In order to further quantify the variations of flow behaviors during waterflooding in the reservoir in Block WX-3, using the experimental data of oil-water relative permeability before and after waterflooding at different watered-out levels, a mathematical model for oil-water relative permeability and a prediction model for water cut changes during the whole process of waterflooding development were constructed by virtue of waterflood analytical method and Newton iteration method. The results show that the actual water cut during production in Block WX-3 changes in a consistent pattern with the model prediction result. The main problems in the development of Block WX-3 are relatively high displacement rate in waterflooding, and the migration, expansion and blockage of clay particles caused by injected water, which alter the pore structure and wettability of the reservoir. Along with extension of water injection, the irreducible water saturation and residual oil saturation gradually increase, and the oil displacement efficiency gradually decreases. Specifically, on average, the irreducible water saturation increases by 0.067 7, the residual oil saturation increases by 0.053 1, and the oil displacement efficiency decreases by 0.142 8.
Chemical flooding is a potential technique for enhancing oil recovery in high-salinity reservoirs. However, the high salinity impacts the viscosity of chemical system, thereby impeding the system’s effectiveness in mobility control and oil recovery improvement. This paper proposes the synergy of nanomaterials with polymer/surfactant for enhancing oil recovery in high-salinity reservoirs. The zero-dimensional nano-particle F80 and two-dimensional nano-sheet GO were compared for their effects on the viscosity and interfacial tension (IFT) of the polymer/surfactant composite system under high salinity conditions. The oil displacement mechanism of the polymer/surfactant composite system before and after the addition of nanomaterials was analyzed depending on the changes in microscopic residual oil and through core displacement experiments. It is found that F80 exhibits stronger ion-dipole interactions with cations in the formation water than GO, and it increases the viscosity of the chemical system by 1.4 times and maintains a lower oil-water IFT. In both microscopic visualization displacement and core displacement experiments, the polymer/surfactant/F80 composite system, with a high viscosity, significantly increases the flow resistance and reduces the dispersed residual oil, and enhances the oil recovery after water flooding by 20.1%, which is 5.4% higher than that of the polymer/surfactant composite system with the same mass fraction.
Repeated high-intensity injection and production in wells of a gas-storage lead to frequent stress changes in the reservoirs, which may trigger sand production to threaten the stable operation of the gas storage. Taking the Yu-37 gas storage in the Ordos Basin as an example, the nodal analysis method was used, together with the critical flow velocity model for proppant migration, as well as the critical sand production pressure difference model for sand production prediction and the critical erosion flow model, to define the reasonable injection and production rates of wells for ensuring the operation safety of the Yu-37 gas storage under the extreme production state. According to the calculation using the critical flow velocity model for initiation of proppant migration in the fractures, which was established through the stress analysis of the proppant in the reservoir fractures, the proppant reaches its critical flow velocity for initiation of migration when the injection and production rates are 10.89 m/s and 8.19 m/s, respectively. Three restrictive models are used to modify the nodal analysis method, the reasonable injection and production rates of Well Yu 43-1 are determined to be (1.79-6.53)×104 m3/d and (2.82-6.35)×104 m3/d, respectively. Given the safety limits, the reasonable injection and production rates of 10 wells at the Yu-37 gas storage are defined.
The high-temperature steam huff-and-puff in the J230 block of Xinjiang oilfield has led to an increased viscosity in residual heavy oil in the formation, significant differences in threshold pressure, and severe fluid channeling. Adding light hydrocarbon solvent can effectively reduce heavy oil threshold pressure gradient. In this paper, viscosity-temperature and rheological tests were conducted to compare the viscosity-temperature curves and rheological properties of heavy oil before and after the addition of light hydrocarbon solvent, and flow experiments were performed to clarify the relationship between the mobility of heavy oil and the pseudo threshold pressure gradient. Finally, a pseudo threshold pressure gradient model for solvent-assisted steam flooding was established. The study shows that the synergy between viscosity reduction by heat and viscosity reduction by light hydrocarbon solvent （or heat-hydrocarbon synergy in brief） allows for an improved performance. Light hydrocarbon solvent can modify the flow capacity of heavy oil. Adding 5%（mass fraction） light hydrocarbon solvent at 40℃ yields a pseudo threshold pressure gradient of heavy oil comparable to that at 70℃. Addition of light hydrocarbon solvent can reduce the quantity of immovable heavy oil. As shown in the pseudo threshold pressure gradient diagram, when the mass fraction of light hydrocarbon solvent added is 0.5%, 2.0%, and 5.0%, the quantity of immovable heavy oil is reduced by 39.13%, 70.56%, and 87.14%, respectively. Addition of the light hydrocarbon solvent can reduce steam consumption, thereby effectively lowering the pseudo threshold pressure of heavy oil, and thus suppressing fluid channeling.
The Junggar Basin holds abundant mixed shale oil, with total resources of 34.9×108 t booked, which is the main strategic target for Xinjiang oilfield to achieve additional reserves and production. However, the strong heterogeneity of mixed shale oil reservoirs makes sweet spot identification and evaluation challenging, limits the promotion of available technology system, and threatens the large-scale and cost-effective development. The enrichment patterns and reservoir characteristics of shale oil in the Junggar Basin, and the corresponding engineering processes/technologies are systematically analyzed in this paper. The technologies formed during the exploration and development of mixed shale oil are summarized, mainly with respect to sweet spot identification, supporting engineering, and development deployment. The differential enrichment theory of mixed shale oil is constructed, and a cost-effective shale oil productivity model integrating sweet spot identification, three-dimensional deployment, excellent fast drilling and completion, efficient fracturing, and environmental protection is established. These achievements support the construction of the first national demonstration zone for continental shale oil in China, and guide the efficient exploration and development of continental shale oil in the country.
In the Jimsar sag, the replacement areas for shale oil development in the Lucaogou formation contain abundant resources, but exhibit small reservoir thickness and heterogeneous sweet spot distribution. Through experimental tests involving organic geochemistry, petrology, pore structure, and hydrocarbon occurrence/mobility, a comprehensive evaluation was conducted on the source rock, crude oil property, reservoir lithology, pore type, and shale oil occurrence/mobility in the replacement areas. The results show that the replacement areas have favorable source rock conditions, and have generally experienced two oil-generating peaks, with significantly lower crude oil density and viscosity and a higher proportion of light components, as compared with the primary zones. The reservoirs in the replacement areas are characterized by small thickness and fine grain size, with underdeveloped intergranular pores but relatively developed dissolution pores and intercrystalline pores, demonstrating a similar pore size range to the primary zones but smaller pore-throat radii than the latter. Both the replacement areas and primary zones hold oil in multiple types of pores, with similar shale oil occurrence patterns. The lower limit of pore size for free hydrocarbon occurrence in the replacement areas is 40-60 nm, which is smaller than that in the primary zones. Crude oil viscosity has a significant control effect on shale oil mobility. Under low viscosity conditions, the crude oil in the replacement areas is highly mobile, with a smaller cutoff than the primary zones according to the nuclear magnetic resonance (NMR) mobility interpretation. The movable oil quantity, oil saturation, pore pressure, and brittleness are the key factors affecting the productivity of the replacement areas. Based on these research insights, a sweet spot evaluation technique combining the weights of these four factors was reconstructed, revealing an accuracy of sweet spot identification in the replacement areas exceeding 80%. The research results provide theoretical support for the stable production of shale oil in the Lucaogou formation.
In response to the challenges in enhancing volumetric stimulation effectiveness in the shale oil reservoirs of the Lucaogou formation in the Jimsar sag of the Junggar Basin, a systematic study was conducted. Based on the lithological assemblage characteristics and geomechanical parameters of the study area, numerical simulation was employed to analyze the propagation patterns of hydraulic fractures under different lithological assemblages. The research focused on the controlling effects of interlayer strength, in-situ stress, interface strength coefficient, displacement, and horizontal well placement on fracture propagation, and explored a differentiated optimization method for fracturing stages. The results indicate that an increase in the elastic modulus of the reservoir/barrier layers and a decrease in tensile strength both facilitate vertical fracture propagation, whereas a high horizontal stress difference significantly inhibits vertical fracture extension. A critical threshold exists for the interlayer interface strength coefficient, which directly governs fracture propagation behavior. Under this critical condition, high displacement promotes fracture penetration through barriers, while low displacement lead to fracture diversion along interfaces. Well placement exhibits a limited impact on fracture geometry, as effective vertical propagation can be achieved regardless of whether the horizontal well is placed within the reservoir or barrier layers. A nonuniform staging scheme based on geological-engineering sweet spot evaluation effectively enhances stimulation efficiency and reduces ineffective operations. This research results provide theoretical support and practical guidance for optimizing horizontal well trajectory, fracturing stage design, and treatment parameters in the shale oil development of the study area.
In light of the geological characteristics of continental shale oil reservoirs，a numerical model for unbalanced fracture propagation during horizontal well intensive fracturing was constructed using the cohesive zone method to study the effects of cluster spacing and lamina on unbalanced propagation of multiple fractures and then elucidate the mechanism of unbalanced fracture propagation during horizontal well intensive fracturing. True triaxial physical simulation experiment was conducted on samples taken from the field outcrop of shale oil reservoirs to investigate the mechanical behaviors of multi-fracture initiation and cross-interface propagation and thereby reveal the mechanism of mechanical interaction between fractures and lamina during intensive fracturing. Comprehensive analysis indicates that the development degree of lamina in shale oil reservoirs is the key determinant of the complexity of fracture network. Increasing cluster spacing effectively enhances the connectivity of the lamina and interfaces. The difference in propagation rate among fracture clusters decreases with the increase of cluster spacing，and the central fractures are more prominently affected by stress interference when cluster spacing is small. The multiple-clustered fractures exhibit a mutually complementary propagation pattern. Reasonably controlling cluster spacing can improve the vertical extension of fractures，thereby expanding the coverage of fracture system and enhancing the fracturing efficiency in shale oil reservoirs.
The Jimsar Shale Oil Demonstration Area in the Junggar Basin, one of the first national continental shale oil demonstration areas in China, has entered the stage of large-scale production. Due to geographical constraints, the well placement optimization and design are indefinite. A reliable geological model is established based on the geology-engineering integration and deviation of well azimuth and operation parameters are optimized through numerical simulation. The results indicate that the platform exhibits characteristics of normal-fault stress, with the minimum horizontal principal stress of 62-72 MPa. The simulated hydraulic fracture length is about 85% of the microseismic monitoring results, and the simulated hydraulic fracture height is similar to the wellbore temperature monitoring results. As the angle between the well azimuth and the maximum horizontal principal stress direction decreases, the hydraulic fracture length increases, while the stimulated reservoir volume (SRV) decreases. Some hydraulic fractures in adjacent sections merge at the part where natural fractures are present, and the proportion of repeated stimulation and degree of heterogeneity of such fractures increase. This suggests that for wells with small angle, the fracturing section length can be extended or the number of clusters in a single section be reduced properly. It is recommended that the optimal well spacing be 200-300 m when the deviation of well azimuth does not exceed 60°, and the optimal well spacing be decreased to maintain a high oil recovery when the well azimuth deviates greater than 60°.
The Jimsar Shale Oil Demonstration Area in Xinjiang, China’s first national-level lacustrine shale oil demonstration area, is in the middle to late stage of development. The concentrated placement of horizontal wells and large-scale fracturing have led to fracture activation, causing casing deformation and impeding the development progress. Considering that the conventional numerical simulation of casing deformation yields results with low accuracy of multiple types of faults in strike-slip fault zones, a strike-slip fault induced casing deformation model was established and then combined with engineering practices to reveal the factors controlling the casing deformation induced by strike-slip fault. The results show that the casing deformation is mainly controlled by fracture dip, applied fluid pressure, and angle between the fracture orientation and the maximum horizontal principal stress direction. For the section of casing deformation at the risk level 1, the injected liquid volume should be reduced to 65%-70% of the original level as designed, and the temporary plugging should be advanced to the time when the injected liquid volume reaches 300 m3, so that the risk of casing deformation can be effectively mitigated. The research breaks through the limitations of traditional fracturing design in the homogenization treatment of strike-slip fault zone, and provides a theoretical basis for the prevention of casing deformation and efficient development of shale oil in complex fault systems.
In order to determine the oil-water relationship and its controlling factors in the shallow heavy oil reservoirs of the Qigu formation in Block HQ1, Karamay oilfield, the study focuses on the h-4 well area, which exhibits significant oil-water distribution complexities at the reservoir margins. Using the data of dense well pattern and test analysis, the influences of sand body distribution, hydrodynamic conditions, reservoir properties, hydrocarbon charging pressure, and tectonic activities on the oil-water contact (OWC) are identified. The h-4 well area demonstrates distinctive OWC characteristics, where the water boundary is parallel with the structural line in the east, and the water boundary obliquely intersects the structural line in the west, resulting in a tilted OWC. This tilted OWC is believed to have been resulted from the periodical fracture opening due to tectonic activities and the OWC adjustment hysteresis is caused by oil viscosity variation, indicating a coupled mechanism of tectonism and unsteady reservoir formation. The fracture opening in the western part of the study area provided oil migration pathways, facilitating oil accumulation in the Qigu formation. Subsequent fracture sealing and reactivation events led to reservoir compartmentalization, creating a OWC that is high in west and low in east. Oil biodegradation shaped a similar viscosity feature. The combined effects of tectonic activities and viscosity variations significantly retard horizontal adjustments of OWC, characterizing the reservoir as a unsteady hydrocarbon accumulation system.
Existing flow unit classification is primarily conducted under static conditions, making it difficult to reflect the dynamic changes in reservoir properties during water injection. To investigate the dynamic changes in reservoir flow units during water injection for optimizing the dynamic detection and development plans, this study takes the Yan-81 layer in the Jiyuan area of Ordos Basin as an example. The static evaluation parameter of the flow unit is defined as the flow zone index (FZI). By fitting the relationship between the cumulative water injection volume and the change in FZI (ΔFZI), the change in FZI caused by water injection is combined with the static evaluation parameter of the flow unit to form a dynamic evaluation parameter of flow units. The results show that as a standard for flow unit classification, FZI is correlated with the results of injection profile tests. Using FZI as the static evaluation parameter, the flow units are classified into three types (i.e. Ⅰ, Ⅱ, Ⅲ). By comparing the reservoir properties at various stages, it can be seen that as water injection continues, the reservoir properties are gradually improved to facilitate fluid flow. Given the same water injection rate, the increase in FZI for Type Ⅲ flow units is significantly higher than those for Type Ⅰ and Type Ⅱ, but its increase rate is lower than those of Type Ⅰ and Type Ⅱ.
Edge and bottom water are found in the Jurassic oil reservoirs in the Ordos Basin. In this kind of reservoirs, rapid water cut rise and low recovery by water flooding occur after initital production. In order to explore new methods for enhanced oil recovery in such reservoirs and find new ways to increase production by carbon sequestration in near-abandoned reservoirs, a pilot test was conducted on top CO2 injection for flow field reconstruction in the Y9 reservoir in the X1 block of Jiyuan oilfield. Through the mechanism analysis of CO2-assisted gravity drainage, multiphase and multi-component numerical simulation was performed to understand the sensitivity and adaptability of the reservoir's geological parameters, and the reservoir engineering parameters were also optimized for the test area. The results show that the residual oil in the Jurassic bottom water reservoirs after waterflooding mainly exists in three forms: thick oil ring in the zone between injection and production wells after the invasion of bottom water, thin oil ring in the zone from the outer oil-bearing edge to the oil production well due to bottom water coning and edge water intrusion, and residual oil after waterflooding. Injecting CO2 at the reservoir top is an effective way to inhibit bottom water coning. As an artificial gas cap forms and exaggerates, gas-oil contact moves downwards, and accordingly oil-water contact becomes lower, alleviating bottom water coning. The main factors affecting CO2-assisted gravity drainage include formation dip, reservoir thickness, permeability, heterogeneity, crude oil properties, and oil saturation, etc. Simulation studies and pilot tests indicate that CO2-assisted gravity drainage at the reservoir top can effectively reconstruct the flow field in waterflooding reservoirs, thereby enhancing the ultimate recovery.
In the western Sichuan depression of Sichuan Basin, the gas reservoir in the second member of Xujiahe formation (Xu-2 member) is a typical fault-fracture tight sandstone gas reservoir. Natural fractures are well developed in the reservoir, with a strong connectivity. The gas wells initially produce at high rates, but cannot maintain stable yield due to water invasion. To identify the causes of water production and determine the water invasion pathway, scale, and timing, gas wells were classified depending on their dynamic characteristics such as production rate and pressure. By analyzing the distribution of gas and water and the fracture characteristics of the reservoir, water invasion patterns were identified, and a numerical simulation model which can reflect these patterns was established. Based on the results of the numerical simulation, criteria for determining water invasion patterns were established, and the simulation results were verified using water analysis data from gas wells.
Ultra-deep fault-controlled fractured-vuggy reservoirs are typically characterized by deep and large fault-controlled hydrocarbon accumulation and preservation. Under the influence of multi-stage tectonism and paleokarstification, the reservoirs have strong heterogeneity and stress sensitivity, leading to unclear inter-well connectivity during the oilfield development process and complex inter-well connection modes, which greatly affect the performance of water/gas injection in production wells. As a fundamental task guiding the waterflooding development of fault-controlled fractured-vuggy carbonate reservoirs, the judgment of the inter-well connectivity is of vital significance. This paper proposes a dynamic-static collaborative analysis method by multi-source data fusion. Based on the division results of statically connected units, using the production performance data and pressure data, several methods such as static pressure analysis, quasi-interference analysis, and production feature similarity, are combined with the well test responses to judge the dynamic connectivity of the statically connected units in the study area. Meanwhile, the changes in the connectivity are analyzed. The proposed method gets ride of the problems of insufficient multi-source data fusion and low efficiency of development data existing in conventional inter-well connectivity analysis.
The ultra-deep fault-controlled volatile reservoirs in Shunbei oilfield are characterized by great burial depth, significant thickness, and tabular distribution, with weak natural energy and rapid decline in both pressure and production during development. Early practice revealed that rapid water injection and high-rate gas injection tend to induce channeling through high-conductivity pathways between wells, compromising displacement efficiency and sweep volume. This paper presents a 3D composite gas-water injection-production strategy. To be specific, water injection is supplemented with gas injection for energy replenishment, so that injector-producer patterns are established with injecting water at lower position and producing oil from higher position, and injecting gas into higher position and producing oil from lower position, forming a 3D well pattern for composite gas-water injection and production. Water injection targets the unswept oil between wells and in middle-lower zones around wellbores, while gas injection displaces the oil at the top, thereby enhancing displacement efficiency and expanding sweep volume to ensure a long-term energy stability of the reservoir. Guided by this strategy, a typical composite gas-water drive unit is projected to enhance oil recovery by 26.0%, restore reservoir pressure by 9.0 MPa, reduce the gas-oil ratio to 820 m3/t, and increase flowing pressure to 45 MPa.
The fractured-vuggy carbonate reservoirs formed under different karst geological backgrounds in Tahe oilfield are being developed by nitrogen injection, with varying effects and unknown controlling factors, which will affect overall planning and deployment of subsequent nitrogen injection. On the basis of revealing main mechanism of nitrogen injection to enhance oil recovery in fractured-vuggy reservoirs, by using the “two baselines and three zones” economic evaluation method for nitrogen injection and field statistics method, the effects of nitrogen injection in these fractured-vuggy reservoirs were clarified, and the key controlling factors were analyzed on the basis of the dynamic and static parameters of the reservoirs. The results indicate some differences in various reservoirs: for weathered crust reservoirs, the proportion of ineffective wells is 40% for individual wells, and 31% for well groups, demonstrating the problems such as long gas injection time and difficulty in continuing conventional gas injection; for composite reservoirs, the proportion of ineffective wells is 24% for individual wells, and 27% for well groups, remaining in the stage of low-cycle gas injection and promising for nitrogen injection in the future; and for fault-controlled reservoirs, the proportion of ineffective wells is 57% for individual wells, and 66% for well groups, recording the poorest adaptability to gas injection. Key factors controlling the single-well gas flooding effect are determined as the reservoir type, attic size, reservoir compartmentalization, structural amplitude, remaining oil reserves at the vug top, energy of the bottom water, and injection/production parameters. Key factors controlling the nitrogen injection effect of well-groups are clarified as the injection-production site, dominant channel between wells, aquifer volume multiple, injection/production parameter, and injector pattern.
