Application and Optimization for Network-Fracture Deep Acidizing Technique of Fractured Carbonate Reservoirs

AbstractThe fractured carbonate rock reservoir is widespread in Sichuan Basin, and the characteristics of different areas are different. The development of natural fractures is varying degrees, lost circulations occur frequently, and the formation heterogeneity is strong, which causes the formation not sufficiently stimulated by acidizing. It may affect the effectiveness of reservoir stimulation. To advance the whole stimulation effect of the heterogeneous fractured carbonate reservoir, a new solution for determining the invasion radius during drilling in a fracture network reservoir is presented, which is based on solute transport and convection-diffusion equations. It can predict the invasion radius caused by mud loss and determines the range of mud loss invasion, which clarify the scope and degree of reservoir damage. The formation of skin factors polluted by mud loss was calculated. The experiments verified that the acidizing technology can remove reservoir damage and reduce the polluted formation of skin factors. The opening pressure of the nature fracture closed is calculated which can control the acidizing area. It is confirmed how many fractures in the carbonate reservoir can be opened under the wellhead pressure limit, which meets the construction conditions of acidizing fractured reservoirs. The framework of network-fracture deep acidizing technology was established, which can efficiently break through the detrimental zone caused by lost circulation, break down the natural fracture network, and decrease the formation of the skin. The restart pressure of natural fractures was calculated, and the design parameters such as pump pressure and displacement were optimized to quantify the scope of reservoir stimulation and the scale of acid fluid. The technique of network-fracture deep acidizing was applied for well A, the formation of skin after acidizing can be reduced to -4, and the testing production of well A was 58.87×104 m3/d. The technique of network-fracture deep acidizing can quantify the acid scale and sweep area in acid fracturing design, which develops the fracturing efficiency and improves the fracturing engineering

Effects of constraint between filaments on the radial compression properties of poly (l-lactic acid) self-expandable braided stents

With the application of bioresorbable materials in self-expandable braided stent, current analytical model for radial compression property of the stent is not applicative if considering the constraint between the polymeric filaments. Poly (l-lactic acid) (PLLA) is one of the broadly used bioresorbable materials in stents due to its superior biocompatibility and mechanical properties. The radial compression properties of PLLA braided stents were investigated by considering two types of constraints between filaments in this work. Weak constraint indicates the friction between filaments of PLLA stents and strong constraint indicates the close looped end (extremity configuration) of PLLA stents. It is found that the radial stiffness can be enhanced by two types of constraints, and strong constraint improves the peak compression force slightly in the radial compression behavior of PLLA braided stents. This work provides suggestions for the study of PLLA braided stents theoretical development

Experimental Evaluation of the Rheological Properties and Influencing Factors of Gel Fracturing Fluid Mixed with CO₂ for Shale Gas Reservoir Stimulation

Foam gel fracturing fluid has the characteristics of low formation damage, strong flowback ability, low fluid loss, high fluid efficiency, proper viscosity, and strong sand-carrying capacity, and it occupies a very important position in fracturing fluid systems. The rheological properties of gel fracturing fluid with different foam qualities of CO2, under different experimental temperatures and pressures, have not been thoroughly investigated, and their influence on it was studied. To simulate the performance of CO2 foam gel fracturing fluid under field operation conditions, the formula of the gel fracturing fluid was obtained through experimental optimization in this paper, and the experimental results show that the viscosity of gel fracturing fluid is 2.5 mPa·s (after gel breaking at a shear rate of 500 s−1), the residue content is 1.3 mg/L, the surface tension is 25.1 mN/m, and the interfacial tension is 1.6 mN/m. The sand-carrying fluid has no settlement in 3 h with a 40% sand ratio of 40–70-mesh quartz sand. The core damage rate of foam gel fracturing fluid is less than 19%, the shear time is 90 min at 170 s−1 and 90 °C, the viscosity of fracturing fluid is >50 mPa·s, and the temperature resistance and shear resistance are excellent. The gel fracturing fluid that was optimized was selected as the base fluid, which was mixed with liquid CO2 to form the CO2 foam fracturing fluid. This paper studied the rheological properties of CO2 foam gel fracturing fluid with different CO2 foam qualities under high temperature (65 °C) and high pressure (30 MPa) and two states of supercooled liquid (unfoamed) and supercritical state (foamed) through indoor pipe flow experiments. The effects of temperature, pressure, shear rate, foam quality, and other factors on the rheological properties of CO2 foam gel fracturing fluid were considered, and it was confirmed that among all the factors, foam quality and temperature are the main influencing factors, which is of great significance for us to better understand and evaluate the flow characteristics of CO2 foam gel fracturing fluid and the design of shale gas reservoir fracturing operations

Sedimentary environment and shale gas exploration potential of Qiongzhusi Formation in the upslope area: A case study on Well W-207, Weiyuan area, Sichuan Basin

To deeply analyze the thalassochemical conditions and organic matter enrichment mechanism during the Early Cambrian (541-509 Ma)and actively evaluate the potential of shale gas resources of the Lower Cambrian Qiongzhusi Formation(Fm) in the southwestern Sichuan Basin, based on the analysis of the petrology, organic geochemistry, element characteristics, pore structure and adsorption capacity of Qiongzhusi Formation, Well W-207, Weiyuan area, this study has discussed the Early Cambrian paleo-ocean environment, organic matter enrichment control factors and gas-bearing properties of shale gas in the upslope area of the Upper Yangtze Platform. Sedimentary cycle shows that multiple interactive conversioncycles of deep-water continental shelf and shallow-water continental shelf are developed during the fine-grained deposition period of Qiongzhusi Formation under the control of eustasy. In particular, the slope turbidite (fan) and gravity flow sediments indicate that shallow-water continental shelf facies are dominant, and the wells in the upslope of the Weiyuan area are not in deep-water for a long time, with the sedimentary thickness of organic-rich black shale limited. Organic geochemistry evidence indicates that the organic matter of Qiongzhusi Formation in Well W-207 is mainly Type-Ⅰ kerogen, with a high degree of thermal evolution, fewer residual hydrocarbons and a low hydrocarbon generation capacity. The redox parameters indicate that the marine environment on the upslope has a medium restrictive degree, and there is a certain degree of upwelling. The seawater has experienced the transformation process of "anoxic-oxidation-anoxic-secondary oxidation- oxidation". Therefore, the paleo-ocean productivity level in the upslope area is generally low, with an obvious downward trend from bottom to top. The pore structure and nitrogen adsorption curve show that the reservoirs of the Qiongzhusi Formation are mainly complex and irregular slit pores. The methane adsorption capacity is positively correlated with TOC but negatively correlated with temperature, indicating that the high-pressure and high-temperature conditions generally faced by the Qiongzhusi Fm are not suitable for methane adsorption. As a result, the geological conditions of shale gas for Qiongzhusi Fm in the upslope area are complex. With high exploration risk, this study suggests that the resource evaluation direction should change to the intracratonic sag (downslope area), which is characterized by deep-water continental shelf facies