A New Mathematical Model of Tight Formation for Productivity Transient Analysis with Additional Gas Driving

During the gas injection development of low-permeability carbonate reservoirs, due to the complexity of the reservoir and the complexity of the fluid phases, the current productivity evaluation methods are no longer applicable. In this paper, considering factors such as fracture characteristics, stress sensitivity, and phase distribution, a low-permeability carbonate reservoir gas injection development productivity transient analysis model is established. The results of the study show that the larger the value of permeability damage coefficient, the stronger the curve of the production curve will bend toward the pressure axis. This is because the larger the value of permeability damage coefficient, the more severe the stress sensitivity of the formation is, which shows that rock deformation has an important impact on production. When two phases appear at the bottom of the well, the seepage resistance increases due to the two-phase flow, which in turn causes the productivity of a single well to rapidly decrease. With the decrease of bottom hole pressure, this resistance will increase significantly and the productivity of a single well will decline rapidly.

A Mathematical Model for Estimating Fracture Permeability with Invasion Damage of Formation Sand

Summary Fracture packing is a well-known completion technique used in the hydraulic fracturing of low-permeability reservoirs. As much as fracture packs are very effective, the proppant-pack permeability damage formed from particle intrusion reduces that effectiveness because it causes low well productivity. It is important to address the issue of permeability damage caused by formation-particle intrusion. An analytical model was developed in this study to predict the permeability of proppant packs in hydraulic fractures with consideration of different levels of invasion damage of formation sand. The accuracy of the model was verified by model comparison with data from the Eagle Ford Shale field. The model result shows that for the Eagle Ford field and the corresponding proppant size used, three blocking levels were achieved that correspond to high proppant-pack permeability. Three case studies were considered in this study: California sand, Gulf Coast sand, and South China Sea silt. The proppant-pack permeability damage was calculated using the analytical model for three levels of invasion for all case studies. The results from applying the analytical model on the three case studies showed the amount of invasion that is possible in each sand according to the proppant size used. The level of invasion is a factor of the sand distribution and the initial proppant size chosen. More analysis showed that for two of the case studies, only Levels 1 and 2 blockings can develop, while for the last case study, three blocking levels considered can develop. This study, for the first time, gives an insight into how selecting the optimal proppant size can improve sand-control performance while enhancing fracture conductivity.

A Novel Model for Predicting the Well Production in High-Sulfur-Content Gas Reservoirs

High-content H2S gas reservoirs are important for natural gas extraction. However, the precipitation and deposition of elemental sulfur in high-sulfur-content gas reservoirs eventually lead to porosity and permeability damage, resulting in the low well productivity. Therefore, it is worth developing an accurate production prediction model considering sulfur deposition for fractured horizontal wells. In this study, based on the partition model and transient percolation theory, a novel numerical model considering the damage of sulfur deposition with pressure change on reservoir porosity and permeability was first developed to predict the production from fractured horizontal wells in high-sulfur-content gas reservoirs. Then, it was validated by actual field data from a high-sulfur-content gas reservoir. After that, the influence of sulfur deposition on the production of fractured horizontal wells was revealed through theoretical calculations, and the effects of hydraulic fracture parameters on production were analyzed. The results show that elemental sulfur gradually deposits in the reservoir pores as the reservoir pressure decreases and the production time increases, which eventually leads to permeability damage and reduces reservoir productivity; this negative impact gradually increases over time. It is also shown that the production of fractured horizontal wells increases with an increase in the half-length, fracture conductivity, and fracture number. Compared with the fracture half-length, the fracture conductivity and fracture number have a greater influence on the production of a single well. The model can handle the influence of nonlinear parameters caused by sulfur deposition, which allows accurate calculations and provides guidance for the development of fractured horizontal wells in gas reservoirs with high sulfur content.

Stress-sensitive permeability of matrix cores and artificially fractured cores with non-proppant-filled fractures under high-pressure conditions

Stress-sensitive permeability (SSP) influences gas well productivity and is a crucial element influencing gas reservoir development. SSP for high-pressure fractured gas reservoirs with an initial reservoir pressure of more than 20 MPa has never been comprehensively evaluated to the best of our knowledge. SSP experiments with special procedures were designed by adopting the variable confining pressure (VCP) and variable internal pressure (VIP) methods. VCP is a test method in which confining pressure is altered and a constant internal pressure is maintained for the experimental core holder. VIP is a test method in which internal pressure is changed and a constant confining pressure is maintained. A four-stage curve analysis method was developed to perform regressions on semi-logarithmic curves and exponential curves of experimental data. A method to evaluate the SSP was presented using stress sensitivity coefficients obtained via regressions. A calculation approach for determining the degrees of permeability damage and permeability recovery was also proposed. Six matrix cores and six cores with artificial fractures from a high-pressure fractured sandstone gas reservoir were tested using the two methods. The SSP curves for high-pressure reservoirs were characterized by four-stage variation trends, which differentiated with low-pressure reservoirs with an initial reservoir pressure less than 20 MPa. The stress sensitivity of the VCP method was stronger than that of the VIP method. The core samples mainly showed a “Medium” / “Medium-Strong” stress sensitivity under low/high effective stress conditions. Compared with matrix cores, fractured cores showed stronger stress sensitivity owing to its strong plasticity and weak elasticity. The maximum permeability damage degree reached 99.67% and the minimum permeability recovery was only 6.9%. The presented method of experimental design, four-stage curve analysis, stress sensitivity evaluation and the summarized findings in this paper can provide references for future studies on SSP in high-pressure fractured sandstone gas reservoirs.

Stress sensitivity evaluation of ultra-low permeability sandstone reservoir and its influence on oilfield development

Luohe ultra-low permeability sandstone reservoir is a hot block in Yanchang oilfield, which is a potential point for increasing production and reservoir. In view of the current situation that there is no unified stress sensitivity evaluation standard for ultra-low permeability sandstone in the study area, taking the ultra-low permeability sandstone in Luohe district as the research object, the stress sensitivity evaluation of ultra-low permeability sandstone is carried out by using experimental analysis as the main means. The results show that it is more accurate to evaluate porosity by using pore stress sensitivity coefficient instead of pore compressibility coefficient. With the increase of net overburden pressure, the porosity stress sensitivity decreases gradually; the permeability stress sensitivity is evaluated by variable confining pressure. With the increase of confining pressure, the permeability damage decreases. With the decrease of confining pressure, the permeability damage increases, but it can not recover to the original value, so the permeability damage is irreversible; in the low bottom hole pressure stage, stress sensitivity has a greater impact on oil well productivity, while in the high bottom hole pressure stage, stress sensitivity has a smaller impact on oil well productivity; advanced water injection can reduce the adverse effect of stress sensitivity on the development of ultra-low permeability sandstone and maximize the economic benefits. The research results clarify the method of stress sensitivity evaluation, and provide guidance for efficient water injection in the next step.

Role of MMP-9 in Diabetic Retinopathy

Diabetic retinopathy is a common neurovascular complication of diabetic that strike a third of diabetic patients worldwide. Complex mechanism of biomolecules including enzyme and cytokines is related to oxidative stress of constant hyperglycaemia. Vascular permeability damage resulting from endothelial leakage and apoptosis of Muller cell is the main mechanism of retinal damage. MMPs as endopeptidases have an important role in angiogenesis process of retinopathy by working with various molecules of growth factors, chemokines, cytokines and cell adhesion molecules. MMP-9 has been widely shown to be associated with inflammation, blood-retinal barrier disruption, cell apoptosis and neovascularization in the diabetic retinopathy pathomechanism. Keywords: Diabetic retinopathy; MMP; MMP-9; Blood-retinal barrier

Permeability Damage and Supercritical Fluid Storage in the Cauvery Basin Neyveli Lignite Bed Containing Kaolinite Deposits during Alternative Injection of Brine and CO2

A laboratory based investigation has been conducted on permeability damage and CO2 storage or retention in the lignite core during alternative injection of brine and supercritical carbon dioxide. Moreover, anthracite and bituminous coal beds were focused by the scientific community for effective production and reservoir formation damage study. But, now-a-days, lignite based coal bed methane reservoirs have attracted attention for productive exploitation and formation collapse investigation. Hence, for this purpose, a single component injection two phase (Brine + Supercritical CO2) coreflood test analysis under alternative injections were performed to investigate the occurrence of lignite structural collapse, permeability damage, injectivity decline and CO2 retention as well. The experimental study reveals that, due to gravity segregation there is a high rate of fluid saturation in lignite core and also, moderate level of heat transfer coefficient was also noted. Also, lignite core structural collapse under the brine and supercritical CO2 injection at different velocities resulted in huge volume of coal and kaolinite fines concentration. Kaolinite and coal fines migration resulted in pressure change and permeability decline in lignite core. The suspensions produced were passed to microstructural analysis and it revealed that kaolinite fine particle tends to possess a leaflet geometrical structure, which obstructed the cleats and restricted the fluid flow. Subsequently, hysteresis modelling (Pranesh 2018) was applied to this problem to quantify the amount of CO2 retention in lignite core. Additionally, statistical model, multiple linear regression was applied to this problem to validate the experimental model, which showed good agreement.