There are scarce researches on the prediction of collaborative underground gas storage (UGS) capacity and the timing of conversion from the collaborative construction stage to the UGS construction stage. Through core displacement experiments and overburden porosity/permeability experiments, the impacts of long-term water flooding and multiple cycles of gas flooding on UGS capacity were studied. By using the full-diameter core samples from the Sanjianfang formation in Pubei oilfield, an experiment on the whole process of UGS capacity expansion through oil production followed by collaborative UGS operation was carried out for the first time, to identify the influences of multiple cycles of gas flooding on storage capacity, time of capacity establishment, volume proportion of working gas, and recovery rate under two modes (constant-pressure production and regular production). The results show that both long-term water flooding and multiple cycles of gas flooding can improve reservoir properties and can be considered as the factors for increasing UGS capacity. As the number of injection-production cycles increases, the incremental capacity decreases and the working gas volume proportion increases under the two modes. The UGS capacity is basically established after the sixth injection-production cycle under constant-pressure production and after the tenth injection-production round under regular production, with the recovery rate not increasing further. The recovery rate under constant-pressure production is 0.34% higher than that under regular production.
To accelerate the development and utilization of unconventional oil and gas resources in the Turpan-Hami exploration area, the current development of unconventional resources in China is reviewed. Considering the technical difficulties in development and the mature experience in domestic shale oil and tight gas development, the development strategies for unconventional oil and gas resources in the Turpan-Hami exploration area are discussed. The development strategies for unconventional oil reservoirs are proposed regarding different basins, structural units and target zones. For the Permian shale oil reservoirs in the Malang sag of Santanghu basin, multi-layer development strategy is adopted; along with the construction of the largest carbon reduction base in the eastern Xinjiang, the technology of CO2 full-chain energy replenishment + viscosity-reduction volume fracturing for shale oil is vigorously developed to continuously enhance the recovery of shale oil. For the Permian Mazhong tight oil reservoirs in the Santanghu basin, well group multi-media composite huff-and-puff is adopted to enhance the oil recovery to 15.0%. For the Permian shale oil reservoirs in the Ji 28 block in the Jimsar sag, eastern Junggar basin, based on the successful experience in the Jimsar Shale Oil Demonstration Zone, the shale oil sweet spots are classified and evaluated, their distribution characteristics are clarified, and the drilling rate of Type I + II reservoirs is improved, so as to realize the beneficial development of shale oil. For the Jurassic Sanjianfang tight gas reservoirs in the Shengbei sag of Turpan-Hami basin, pilot tests of geology-engineering integration are performed to increase the length of horizontal section and the drilling rate of reservoir sweet spots, so as to improve the production efficiency of the tight gas reservoirs in the Shengbei sag.
Based on the pilot test of the CO2 huff-n-puff well group in the Shanshan oilfield, the injection-production performance and the factors influencing CO2 EOR and storage in high water cut stage in low-permeability and low-viscosity oilfields were analyzed. The results show that, in the Shanshan oilfield (medium-deep burial reservoirs), the injected CO2 stays in a supercritical state, and the characteristics of CO2 injection are similar to those of water injection, showing the problems of uneven vertical sweep and planar breakthrough. The CO2 huff-n-puff can be divided into three stages: transient gas flowback, oil enhancement, and gradual invalidation. Three huff-n-puff wells vary greatly in oil replacement rate, indicating that the EOR effect mainly affected by the degree of remaining oil enrichment. The main mechanisms of CO2 storage are dissolution and mineralization, and the simultaneous storage rate can reach as high as 95.6%.
Low porosity and low permeability sandy conglomerate heavy oil reservoirs in the Permian series of the Lukeqin oilfield in Turpan-Hami basin are usually fractured for recovery due to their poor physical properties, strong heterogeneity and low natural productivity. The induced fractures and reservoir heterogeneity lead to poor water injection effect. In order to solve the problems encountered in the development such as prominent areal contradiction, low efficiency, and ineffective areas, water injection is used to replenish the formation energy for increasing single-well production, but the effect in single wells is quite different. The reservoir wettability and water injection process for energy replenishment were studied through physical simulation experiments. The results show that the Permian reservoirs in the Lukeqin oilfield are water-wetting. Fracturing is conducive to the imbibition between fractures and reservoir matrix, which can effectively replenish the formation energy to improve single-well production. The faster the water is injected, the faster the formation energy can be recovered; the higher the well soaking pressure, the higher the oil increment. Combining numerical simulation and in-situ conditions, the injection parameters were optimized. As a result, the effect of water injection was good, with the effective rate reaching 88%.
Various blocks of a same reservoir might be developed at different time, which leads to the underestimate of oil recovery when using comprehensive reservoir development data to calibrate oil recovery factor. In order to solve this problem, two blocks with different lag time, productivity and OOIP were designed. Through comparative analysis of indexes, the influencing factors were analyzed quantitatively. The results show that, with the same waterflooding model, the recovery factor estimated by superposing cumulative production index is lower than the sum of the recovery factor estimated separately for each block. The larger the proportion of productivity or geological reserves of a new development block and the later the block is developed, the lower the estimated recovery factor through the superposition of cumulative production index. Therefore, when using waterflooding curves to calibrate recovery factor, the oil reservoir should be divided into several units according to the similar production time as possible to calculate the recovery factor separately; otherwise, calculating recovery factor by superposing cumulative production index will result in a lower calibration of recoverable reserves or recovery factor.
The performance of gas huff-n-puff in heavy oil reservoirs in the Tuha exploration area are declining. Gas huff-n-puff experiments were conducted by using PVT analysis technology to simulate high-temperature and high-pressure environment in the heavy oil reservoirs. CO2, natural gas, and nitrogen were injected respectively into the reservoirs, and then evaluated for adaptability in terms of viscosity reduction, swelling effect, foamy oil range, and residual heavy oil properties. The results show that CO2 huff-n-puff is best performed in viscosity reduction, swelling, and foamy oil range, but the injected CO2 has a significant impact on the residual heavy oil properties by increasing the residual heavy oil viscosity and decreasing the gas dissolution capacity, which is not conducive to multiple rounds of gas huff-n-puff. The natural gas huff-n-puff effect is slightly inferior to that of CO2 huff-n-puff, while the nitrogen huff-n-puff exhibits the worst performance but has a little impact on residual heavy oil properties.
To explore the feasibility of natural gas gravity drainage in the Pubei oilfield of the Turpan-Hami basin, the oil displacement characteristics under different operation parameters were clarified. By way of high-pressure physical property analysis, slim tube test, CT scanning imaging, and full-diameter core displacement experiments, the variations of the high-pressure physical properties of the fluids in the Middle Jurassic Sanjianfang formation reservoir before and after the flooding in the Pubei oilfield were analyzed, the minimum miscible pressure of the gas in the Shanshan-Urumqi Gas Pipeline and the West-East Gas Pipeline under current reservoir conditions was calculated, the fluid distribution characteristics and the changes in oil saturation along the core under different displacement methods were compared, and the influences of injection rate, injection pressure, and rock dip angle on natural gas gravity drainage were clarified. The results show that after flooding there are increases in both crude oil density and saturation pressure, an unconspicuous change in viscosity, and significantly decrease contents of C2-C6 contents in the crude oil. The minimum miscibility pressures of the gas in the Shanshan-Urumqi Gas Pipeline and the West-East Gas Pipeline with oil are 48.2 MPa and 49.5 MPa, respectively, both higher than the minimum miscibility pressure of the original oil and gas. Compared with the performance after water flooding, the natural gas gravity drainage reveals very different oil saturations along the core: the oil saturation at the high position of the core is significantly lower than that at the low position, indicating that the natural gas gravity drainage is more effective in displacing the crude oil at the high position. Low injection rate, high displacement pressure, and large dip angle are all beneficial to improving the oil recovery of natural gas gravity drainage.
Water channeling often occurs in gas wells during the production of fractured-porous carbonate gas reservoirs with edge/bottom water. A simulation experiment on water invasion mechanism was performed by using a visualized microscopic model and under the formation conditions simulated by the high-temperature high-pressure online nuclear magnetic resonance detection system, to study the distribution of residual gas. The distribution of intrusive water was characterized by the T2 spectrum obtained from pulse sequence testing. The results show that the pore-throat ratio, coordination number, and fracture width have significant impacts on water invasion and residual gas distribution. In porous reservoirs, invasion water first enters large pores and then small pores. In fractured-porous reservoirs, where the distribution of fractures has an influence on the water invasion mode, intrusive water enters the fractures and then the medium-large pores. In water-invaded porous reservoirs, 37.7% of the residual gas exists in small pores, and 62.3% in large pores. In water-invaded fractured-porous reservoirs, a little residual gas is in fractures, 4.8%-26.8% of the residual gas in small pores (where the residual gas is difficult to recover), and 94.7%-69.2% in medium-large pores. The residual gas saturation index was evaluated with the water invasion proportion in medium-large pores as an objective function, and the main controlling factors include fracture penetration degree, water volume ratio, fracture width and gas production rate. The well trajectory should be optimized in the fracture zones and kept away from the fractures that communicate with edge/bottom water. Furthermore, well production rate should be optimized to delay water breakthrough. After water breakthrough in gas wells, the gas production rate should be appropriately reduced to drive intrusive water into medium-large pores and reduce residual gas in the medium-large pores, thus enhancing the gas recovery.
In X oilfield, the reservoirs exhibit poor physical properties, a small number of layers vertically, and the presence of small faults in complex distribution, which lead to poor effect of vertical well development and ineffecient displacement of the existing well pattern. Based on the successful development of pre-existing horizontal wells and infilled horizontal wells in the pilot test in 2014, a study was conducted on horizontal well infilling and tracking adjustment techniques in the areas with inefficient waterflooding by vertical wells and in the unswept areas near fault zones. Through logging-seismic combination and comprehensive dynamic-static analysis, the areas with stable reservoirs, low water-out risk, and enriched remaining oil were identified for well infilling. By optimizing the orientation and horizontal section length of horizontal wells, the fracturing density and fracture length were optimized to enhance the productivity of horizontal wells. The injection-production process was optimized by implementing the waterflooding tracking adjustment strategy of early-stage intermittent water injection and weak injection via the injector in an adjacent row + strong injection via the injector in a row apart. Following these approaches, a total of 19 infilling horizontal wells were drilled in the X oilfield in 2019, achieving a sandstone-encountered rate of 83.0%. The initial daily oil production per well reached 7.4 t, with a comprehensive water cut of 28.8%. An effective displacement system was established, resulting in an increase in the oilfield’s production rate from 0.8% to 1.5%, and improving the overall development effect of X oilfield.
In order to determine CO2 flooding and storage mechanisms in the ultra-low permeability reservoir in Jiyuan oilfield, long core experiments were performed to understand the performance of enhanced oil recovery (EOR) and CO2 storage under different flooding techniques. The results show that the CO2-water alternating injection after water flooding yields the highest recovery factor, followed by CO2-water alternating flooding, while continuous CO2 injection exhibits the lowest recovery factor. CO2 breakthrough is a crucial factor influencing recovery factor, and alternating injection can suppress gas channeling. CO2 is dominantly stored in the large pores of the reservoir, and the CO2-water alternating flooding is more conducive to CO2 storage in the small pores than pure CO2 flooding. Continuous CO2 injection, CO2-water alternating flooding, CO2-water alternating injection after water flooding, and CO2 injection after water flooding exhibit a descending order in CO2 storage efficiency.
Considering the limited methods for evaluating reservoir development performance using gas-water miscible flooding characteristic curves, a concept of underground water-gas cut was introduced. By analogy with the generalized mathematical model of water cut variation in water flooding reservoirs, generalized gas-water miscible flooding characteristic curves and the corresponding generalized mathematical models of underground gas-water cut variation were established. The generalized gas-water miscible flooding characteristic curve is a Type A water-alternating-gas (WAG) injection characteristic curve when n=0 and m=0, and a Type B WAG injection characteristic curve when n=1 and m=0. By varying the values of n and m, the generalized gas-water miscible flooding characteristic curve can be transformed into S-shaped, convex, S-convex, S-concave, and concave gas-water miscible flooding characteristic curves. For purpose of field application, a general formula for the generalized gas-water miscible flooding characteristic curve and solution method for the corresponding mathematical model combining underground gas-water cut variation were provided. The application to the evaluation of the development performance of WAG injection in the reservoir of Sanjianfang formation in Pubei oilfield, and of gas cap gas + edge water displacement in S31 reservoir in Jinzhou oilfield shows a high fitting accuracy. This method can be a reference for other reservoirs.
The tight oil reservoirs in the MZ block of the Santanghu basin are characterized by medium-high porosity, ultra-low permeability, and high oil saturation. In the initial development stage, high production rate was achieved by virtue of volume fracturing in horizontal wells, but declined greatly. In the late stage, the reserves were effectively produced through water huff-n-puff. After years of development, the effect of water huff-n-puff became worse. The current recovery percent of reserves is only 5.6%. For further enhancing the oil recovery, CO2 huff-n-puff experiments were conducted in five horizontal wells. The results show that CO2 plays a pivotal role in enhancing recovery in tight oil reservoirs through the mechanisms such as swelling, energy augmentation, viscosity reduction, light component extraction, and fluid mobility improvement. The impact of CO2 varies throughout the injection, soaking, and production stages, leading to alteration in crude oil properties. CO2 can enhance oil recovery and also demonstrate a high storage rate, offering both economic and social benefits. CO2 huff-n-puff is adaptable and promising for tight oil reservoir development.
In the Sichuan basin, most of horizontal shale gas wells are stimulated by subdivided fracturing with large-stage and multi-cluster. Large-scale operations at high displacement and well infilling are often associated with severe inter-well interferences, leading to a decrease in well productivity. Optimizing stimulation treatments and well completion strategies and understanding the hydraulic fracture propagation rules are crucial to reducing the risk of inter-well frac-hit. Based on a 3D geomechanical model and with consideration to reservoir heterogeneity, in-situ stress anisotropy, interaction between fractures, and fracture network distribution, hydraulic fracture propagation and frac-hit prevention were simulated for two adjacent horizontal wells. The results show that large horizontal stress difference, natural fracture density and fluid intensity, or small approach angle and cluster spacing, may induce a high risk of frac-hit.
It is difficult to conduct hydraulic fracturing in sandstone-mudstone interbedded reservoirs. Investigating the factors influencing hydraulic fracture propagation in such reservoirs is beneficial for optimizing fracturing parameters and enhancing vertical producing degree of reservoir. The propagation of hydraulic fractures in sandstone-mudstone interbedded reservoirs is primarily influenced by rock mechanics between layers, differences in formation stress, and engineering parameters. The cohesive elements of hydraulic fracture and layer interface are embedded into ABAQUS software to analyze how the displacement and viscosity of fracturing fluid, mudstone-sandstone elastic modulus ratio, tensile strength, and formation stress difference affect vertical fracture propagation. The results show that interface fractures hinder the primary fracture propagation through beds but contribute to reducing the pressure for hydraulic fracture propagation, thereby promoting the formation of fracture network. High displacement and low viscosity of fracturing fluid can promote fracture propagation through beds and accelerate the opening of interface fractures. When the mudstone-sandstone elastic modulus ratio is less than 0.6, the mudstone barrier has a significant shielding effect, and the hydraulic fractures are primarily reverse-H-shaped and weak in prorogation through beds. When the formation stress difference is greater than the tensile strength difference between mudstone and sandstone, fractures propagate greatly in vertical direction, which can serve as a preliminary criterion for assessing the potential of hydraulic fractures to propagate through beds.
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 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.
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 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.
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.
