Geofluids最新文献

As shale gas reservoirs have low porosity and low permeability, hydraulic fracturing is a necessary means for industrial exploitation of shale gas. In this study, aiming at the problem of reservoir damage in the process of hydraulic fracturing of shale gas reservoir, a physical simulation method of slickwater fracturing fluid flow in shale core has been established. The change laws of physical parameters of the shale were quantified after slickwater fracturing fluid filtrating into it. The main factors affecting physical parameters of shale matrix around fractures were found out in the process of fracturing, shut-in, and flowback of slickwater fracturing fluid. The results show that after treated by slickwater fracturing fluid, the wettability of shale becomes more uniform in distribution (the water contact angles from 43° to 48°). In the fracturing filtration zone, the damage rate of fracturing fluid to shale porosity is 6.4%-42.0%. Low differential pressure flowback can reduce the damage of the shale, and prolonging the time of shut-in has no obvious effect on the damage to porosity. After 0.3 d (imbibition stability time), the damage of fracturing fluid to shale permeability is basically stable (55.9%). Permeability damage is mainly caused by residue of the fracturing fluid in large pores and bound water in small pores. Analysis of weights of all fracturing parameters shows that flowback differential pressure has the largest influence weight on shale porosity (51.4%), and well shut-in time has the largest influence weight on shale permeability (62.7%). Therefore, in the production process, it is suggested to properly reduce the backflow differential pressure and moderately shorten the well shut-in time.

Offshore heavy oil resources are abundant, but they have greater difficulty and higher costs compared to onshore extraction. When crude oil flows through the seawater section, the temperature of the crude oil decreases faster, making it susceptible to solidification in the wellbore and resulting in lower well production. The cooling of crude oil becomes more pronounced in deep-water wellbore. However, the injection of low-temperature gas will have a cooling effect on the formation production fluid, which will have a negative effect. The model analyzes the effects of coiled tubing running depth, gas injection temperature, gas injection volume, coiled tubing diameter, and crude oil production on the temperature distribution of heavy oil in deep-water and shallow water wellbores. We propose recommendations for the selection of each parameter for deep and shallow water environments by analyzing and summarizing the laws.

The existing research on CH₄ displacement by N₂ mainly focuses on the gas injection displacement mechanism and the factors affecting displacement efficiency. And most of them are theoretical analyses at the model level or multifactor analyses at the simulation test level, while there are few targeted physical simulation tests and quantitative analyses. Given the above problems, the experiment system was used to study the gas migration evolution law and time-varying characteristics of CH₄ displacement by N₂ in coal under different injection pressures. The experimental results show that the whole process of CH₄ displacement by N₂ can be divided into three stages: stage I (original equilibrium stage); stage II (dynamic balance stage); stage III (new equilibrium stage). The concentration of CH₄ and N₂ presents an opposite variation trend, and the variation rate of CH₄ and N₂ increased first and then decreased. The breakthrough time was 50 minutes, 45 minutes, 35 minutes, 25 minutes, and 20 minutes, respectively, under different injection pressures. The displacement efficiency increased with the injection pressures, while the replacement ratio decreased with the injection pressures. The maximum flow rate of CH₄ was 0.085 mL/min, 0.110 mL/min, 0.130 mL/min, 0.222 mL/min, and 0.273 mL/min, respectively, under different injection pressures. The accumulated production of CH₄ was 3.59 mL, 3.91 mL, 4.39 mL, 5.58 mL, and 5.94 mL, respectively, under different injection pressures. The effective injection pressure range was 1.6~2 MPa. This research can provide a reference for the theoretical research of N₂-ECBM-related technology in low permeability reservoirs and the selection of injection pressure in the field technology implementation.

Since the initial impoundment and commissioning of the Three Gorges Reservoir in June 2003, seismic activity surrounding the reservoir region has undergone substantial changes. Leveraging geological and hydrogeological data from the Three Gorges Reservoir area, this study statistically analyzes the historical water level and earthquake catalog within the reservoir. By examining the correlation between reservoir water levels and earthquake frequency, the relationship between seismicity along the Xiannvshan fault and water level is analyzed. Additionally, the ArcGIS software is employed to evaluate the spatial pattern of earthquake epicenters during the filling of the Three Gorges Reservoir, with the goal of elucidating the impact of water impoundment at the Three Gorges on the activity along the Xiannvshan fault. The results demonstrate the following. (1) There is a complex process of “continuous loading, permeation and saturation, rebound and rebalancing” in the crust of the reservoir head area during the impoundment of the Three Gorges Reservoir area, and the activity of the Xiannvshan fault is closely related to the reservoir water level. (2) At the 135 m impoundment stage, Xiannvshan fault activity is mainly affected by reservoir water level and is positively correlated with reservoir water level. At the 156 m impoundment stage, reservoir water load is still the main influencing factor of Xiannvshan fault activity, but the permeability of reservoir water is enhanced in this stage. (3) The earthquake epicenters near the northern section of the Xiannvshan fault are clustered during the 175 m experimental impoundment stage. During the continuous loading stage, the reservoir water load is still the main control factor of the Xiannvshan fault, and the seismic activity is significantly enhanced. From November 2010 to November 2013, during the permeation and saturation stage, the dominant factor of Xiannvshan fault activity changed from reservoir water load to reservoir water infiltration along the Xiannvshan fault. The period from 2013.11 to 2014.5 was a vertical rebound stage, and the infiltration effect of reservoir water had a more significant impact on Xiannvshan fault activities.

The transient electromagnetic (TEM) method has long been applied in tunnel advanced prediction. However, it remains questionable to what extent a geologic anomaly body will influence the induced electromagnetic response in front of the heading face. The dilemma is partly because observed TEM data are frequently interpreted by empirical formulas or proportional relationships, and a quantitative measurement has not been established. In this paper, we strive to understand the TEM characteristics from a 3D finite-element time-domain (FETD) modeling aspect. The modeling algorithm is based on unstructured space meshing and unconditional stable time discretization, which ensures its accuracy and stability. The modeling algorithm is verified by a half-space model, in which the misfit of late-time channels that we are concerned with is generally below 1%. The algorithm has also been utilized to carry out the TEM response of tunnel models with different types of TEM devices. Through model studies, we find that both the traditional central-loop device and the recently developed weak-coupling opposing-coil device are feasible in tunnel advanced detection. Nevertheless, the latter type of device better distinguishes low-resistivity anomalies at 30 m ahead of the heading face with a relative difference (between models with and without the anomaly) of more than 1000% at certain time channels, compared with only a 10% difference of the central-loop device. Also, we conclude that the vertical electromagnetic field component should be recorded and interpreted together with the horizontal field to provide more convincing results.

Considering that karst caves, underground rivers, and dissolution fractures in shallow carbonate formation in the Sichuan Basin are extremely developed, leakage, failure and plugging difficulties are easy to occur in the drilling process. The TDEM was used to carry out the exploration of hidden karst geological bodies in well QM2, and the quasi-three-dimensional inversion based on lateral constrain was used to invert the TDEM data. Three NW trending anomalous bands were identified in the lower Triassic Jialingjiang Formation within the range of drilling, consisting of seven relatively low-resistivity anomalous zones. Under the guidance of TDEM quasi-three-dimensional inversion resistivity data, the low-resistivity karst development area is avoided, and the specific drilling location of well QM2 is determined. No karst cave and underground river were drilled in the later drilling process of well QM2, as well as no instability phenomenon occurred. It indicates that the TDEM detection results are consistent with the actual drilling, and the quasi-three-dimensional TDEM inversion interpretation data based on lateral constraints is reliable and can accurately detect the buried karst in the wellsite.

Stress sensitivity and the elastic outer boundary (EOB) condition have a great effect on the analysis of the characteristics of the fluid flow in a reservoir. When researchers analyzed the characteristics of the fluid flow, they have considered the stress sensitivity and the EOB condition separately but have not considered them simultaneously. Therefore, errors are inevitable during the analysis of well testing. The main object of this work is to present a well-testing model for stress-sensitivity dual-porosity reservoir (DPR) with EOB to improve the accuracy of the analysis of well-testing data. To this end, in this paper, we established a well-testing model for the DPR, considering the stress sensitivity and the EOB simultaneously, and presented its semianalytical solution. On the basis of the consideration of the EOB condition and stress sensitivity of permeability (SSP), a seepage model for the DPR with the EOB is built using the continuity equation, motion equation, state equation, and interporosity flow equation between matrix and fracture, which considers the stress sensitivity, wellbore storage, and skin. To solve this model, a nonlinear partial differential equation is changed into a linear form of a partial differential equation by introducing an effective well radius and applying Pedrosa’s transformation and perturbation transformation. Applying the Laplace transformation, an analytical solution in the Laplace space is obtained, and curves of pressure and pressure derivative (PPD) are drawn by numerically inverting them. The model is verified by comparing it with the EOB without consideration of SSP and using case data. The sensitivity of parameters on the curves of PPD is analyzed. This work may be significant for evaluating more accurately the parameters of wells and reservoirs using well testing.

Dry hot rock geothermal resources by virtue of its wide distribution, large reserves, clean and low-carbon, stable, high utilization rate, and other characteristics have been widely used. The enhanced geothermal system (EGS) is the most efficient approach for harnessing and exploiting geothermal energy from hot, arid rock formations. To investigate the impact of varying parameters on heat recovery in EGS operations, we employed the COMSOL numerical simulation software to construct a seepage heat transfer model for fractured rock masses. Essential parameters and boundary conditions were established, followed by conducting numerical simulations. Through the numerical simulation results, the temporal and spatial changes of coupling effects among seepage field, stress field, and temperature field in fractured rock mass were analyzed. We investigated the impact of water injection temperature, injection-production pressure difference, injection flow rate, and initial reservoir temperature on the heat transfer process. The findings indicate that raising the water injection temperature and injection-production pressure difference can enhance the reservoir’s heat recovery capability. However, it may also accelerate thermal breakthrough and reduce the system’s operational lifespan. The higher injection flow rate can improve the heat recovery efficiency. However, too large injection flow can cause problems in other aspects of the reservoir; increasing reservoir temperature leads to higher production temperatures, which can potentially result in dynamic catastrophes. Therefore, while ensuring the heat recovery efficiency of the system, the operation life of the system can be extended by adjusting the water injection temperature in stages, setting a reasonable injection and production pressure difference, and selecting an appropriate injection flow rate, so as to achieve the purpose of EGS optimization.

Cyclic injection hydraulic fracturing is a promising way for the geothermal energy exploitation by reactivating the fractures in geothermal reservoir. However, fracture initiation and growth induced by cyclic injection schemes have been inadequately studied for hot dry rock (HDR), and the cyclic injection fracturing optimized often by experience. For this reason, the initiation and propagation of hydraulic fractures in the HDR under different cyclic injection methods were determined by experiment research for hydraulic fracturing. The results show that the cyclic frequency and injection rate play different roles in the stimulation of HDR. The cyclic injection with low frequency-low pressure can create more branched fractures, forming a short but complex hydraulic fracture network. However, when high flow-high frequency injection method is subjected, the branch fractures formed are significantly reduced, but each branch fracture can be fully expanded. To fully exploit the advantages of different injection methods, a numerical model that contains a fracture network was established with PFC software, and an alternating cyclic injection scheme with synergistic control of the cyclic frequency and injection rate was proposed. The comparison results indicated that the alternating cyclic injection method can effectively improve the fracturing effect in the HDR. The stimulation area of the alternating cyclic injection method is about 2.3 times and 2.7 times that of the low flow-low frequency and high flow-high frequency injection methods, respectively. The method presented here can be adopted to optimize the fracture growth regime and provide a scientific basis for EGS hydraulic fracturing design.

The fluid flow behavior, generally referred to as seepage, could determine the hydrocarbon and brine movement behavior. Movable fluid property, as one of the vital parameters for seepage characteristic evaluation, was generally used for tight oil reservoirs’ fluid flow ability assessment. The nuclear magnetic resonance technique was used to experiment with movable fluid percentage and movable fluid porosity, which can provide a realistic assessment of the amount of fluid that can flow in the porous media. Other techniques were also used to analyze the main factors in regulating the differences in movable fluid parameters. However, the research about fluid flow behavior was generally based on traditional methods, while the seepage characteristics from the pore-scale view are still a myth. To promote this process, in this study, core samples obtained from the Chang 7 reservoir of the Triassic Yanchang Formation in the Longdong region of Ordos Basin, China, were tested. The results show that the average movable fluid percentage and average movable fluid porosity of the total 16 core samples are 36.01% and 2.77%, respectively. The movable fluid exists mainly in the midlarge pores with the corresponding T₂ relaxation time over 10 ms. T₂ distributions mainly present four typical patterns: (1) bimodal distribution with similar amplitudes of the two peaks (occupying 6.25%), (2) bimodal distribution with higher right peak and lower left peak (occupying 18.75%), (3) bimodal distribution with higher left peak and lower right peak (occupying 56.25%), and (4) unimodal distribution (occupying 18.75%). Pore structure heterogeneity is closely related to the movable fluid parameters; the movable fluid parameters exhibit a relatively good correlation with core throat radius as well as permeability. There is an obvious difference between the movable fluid parameters and the microscopic characteristic factors in tight oil reservoirs due to the difference in physical properties, clay mineral content, microcracks, and pore structure characteristics. This research has provided a new perspective for the movable fluid property evaluation, and the relevant results can give some advice for the oil field development.