ABSTRACT
Temporary plugging diversion fracturing (TPDF) technology has been widely used in various oil fields for repeated reconstruction of high-water-cut old oil wells and horizontal well reservoir reconstruction. Previous studies have carried out in-depth study on the pressure-bearing law and placement morphology of different types of temporary plugging agents (TPAs) in fractures, but there are relatively few studies on TPA accumulation body permeability. To solve this problem, an experimental device for evaluating the TPA performance with adjustable fracture pores is proposed in this paper. Based on the test of fracturing fluid breaking time and residue content, the low damage of fracturing fluid to the reservoir is determined. The TPA degradation performance test determines whether the TPA causes damage to the hydraulic fracture after the temporary plugging fracturing. Finally, by testing the TPA pressure-bearing capacity and the temporary plugging aggregation body permeability, the plugging performance and the aggregation body permeability are determined. The results show the following: (1) Guar gum fracturing fluid shows good gel-breaking performance under the action of breaking agent, and the recommended concentration of breaking agent is 300 ppm. At 90~120 °C, the degradation rate of the three types of TPAs can reach more than 65%, and it can be effectively carried into the wellbore during the fracturing fluid flowback stage to achieve the effect of removing the TPA in the fracture. (2) The results of the pressure-bearing performance of the TPA show that the two kinds of TPAs can quickly achieve the plugging effect after plugging start: the effect of ZD-2 (poly lactic-co-glycolic acid (PLGA)) particle-and-powder combined TPA on forming an effective temporary plugging accumulation body in fractures is better than that of ZD-1 (PLGA) pure powder. There are large pores between the particles, and the fracturing fluid can still flow through the pores, so the ZD-3 (a mixture of lactide and PLGA) granular temporary plugging agent cannot form an effective plugging. (3) The law of length of the temporary plugging accumulation body shows that the ZD-2 combined TPA has stronger plugging ability for medium-aperture simulated fracture pores, while the ZD-1 powder TPA has stronger plugging ability for small aperture simulated fracture pores, and the ZD-3 granular TPA should be avoided alone as far as possible. This study further enriches and improves the understanding of the mechanism of temporary plugging diverting fracturing fluid.
ABSTRACT
During hydrate exploitation, the formation and decomposition of hydrate in the wellbore are affected by many factors such as salinity, temperature, pressure, gas-liquid ratio, and so on. In the drilling process, inhibitors will be added into the drilling fluid, to prevent the formation of hydrates in the wellbore to form blockages. In order to explore the influence of these factors on the formation and decomposition of hydrates, a visual wellbore simulator was used to study the formation, inhibition, and decomposition of hydrates in the wellbore, which affected these factors. First, the accuracy of device was verified, and then the effects of water type, pressure, inhibitor, and gas-liquid ratios (GLR) on methane hydrate (MH) formation were studied. The results show that (1) In fresh water, after the formation of methane hydrate, the pressure of methane gas in the container drops by 6.73 MPa, while in 10% NaCl brine, the pressure of methane gas in the container only drops by 1.24 MPa, since the NaCl is a thermodynamic inhibitor, which inhibits the formation of MH, the amount of dissolved gas in the brine is less, resulting in less pressure drop within the container. (2) Compared with fresh water, the kinetic inhibitor GID3 can better inhibit the generation of MH, but when the dosage of GID3 is 1.0 and 2.0 wt %, the pressure drop of MH in the container is 0.71 and 2.18 MPa, respectively. Therefore, excess inhibitor will reduce its inhibitory effect. (3) When the pressure and GLR increase, the hydrate can absorb more methane after it is formed. However, when there are inhibitors in the fluid, the law of dissolved methane becomes complicated. (4) Appropriate decomposition solution helps to accelerate the decomposition of MH and reduce hydrate blockage in the wellbore during drilling. This article provides a reference for the formation of hydrate in the wellbore during hydrate exploitation.
ABSTRACT
Yudong (YD) 7 reservoir in the Yingmaili area of Tarim Oilfield is one of the key areas of oil and gas exploration in the Tarim Basin. However, due to the serious plugging problem caused by solid phase precipitation particles such as wax and paraffin, it is necessary to study the well flow phase behavior and solid phase precipitation law of typical high-production wells in this block to obtain the phase enveloping line and provide theoretical support for preventing solid phase precipitation of formation crude oil. In this study, the PVT tester and the self-designed microscopic solid deposition tester are used to obtain the phase enveloping line of formation crude oil, and the change law of the "gas-liquid-solid" phase behavior when the formation crude oil changes with temperature and pressure is observed. The morphological process of solid precipitation is recorded and analyzed through a microscopic visualization window. Finally, the solid phase precipitation point of formation crude oil is verified using a laser solid phase deposition tester. The experimental results show that under atmospheric pressure, the solid phase precipitation temperature point of surface crude oil is 34.05 °C, the maximum instantaneous precipitation is 0.01178%, and the maximum cumulative precipitation is 8.34%. The solid phase precipitation point of formation crude oil changes under different temperatures and pressures. Under different pressures and temperatures, it shows multiphase changes such as liquid-solid, liquid phase, gas-liquid-solid, gas-liquid, and gas phases. Limited by equipment, we can only observe the first four phase behaviors in the laboratory. In the process of solid phase precipitation, formation crude oil shows a fine needle shape at the initial stage and finally adhesions and aggregations in the form of an increasing crystal nucleus as the center, thus blocking the formation or wellbore. Combined with the analysis of production data, it can be seen that there is a solid precipitation problem in well YD 702 over 1200 m in the wellbore and the solid phase precipitation problem from the wellbore to the surface pipeline. This study provides theoretical support for preventing solid phase precipitation in the YD 7 reservoir and provides a reference for other oil fields with solid phase precipitation blocking problems.
ABSTRACT
Research shows that the surface shape of rotary liquid depends on the rotation mode. Mode A is that when the container wall rotates the liquid, the rotating liquid surface is paraboloid. Mode B is that when the rotor in the center of the container rotates the liquid, the rotating liquid surface is vortex. Based on the paraboloid formed by the mode A, the identity between the liquid level parameter and the wall slope K (K ≠ 0) is derived. When K â ∞, with the increase of the container angular spin rate, the liquid level parameter changes are infinite, the liquid level change and volume relationship are fixed. When K > 0, the container is a cylinder with a large upper part and a small lower part and the liquid level parameter changes are limited, and the limit ratio between the liquid level parameters is + 1. In addition, through the vortex experiment by the mode B, it is concluded that the vortex curve can be regarded as composed of three parabolas: the center triggering part, the rising part, and the edge attenuation part. Different from the mode A, the liquid level change and volume relationship caused by the vortex formed by the mode B are both variables. According to the experimental results, the influences of container inner diameter, initial liquid level, rotor size, and rotor speed on the vortex characteristics are discussed in detail. At the same time, based on the experiment, the liquid level change and volume relationship caused by the formation of the vortex are deduced under the ideal condition when a stable liquid surface is formed by the vortex.
ABSTRACT
The surface of a tight reservoir appears to be oil-wet or mixed-type wet upon soaking in crude oil for a long time, and the yield decreases rapidly after fracturing under the influence of capillary force. The oil sweep efficiency affected by many factors such as formation water dilution, salinity, crude oil type, temperature, and pressure can be enhanced by adding nanosurfactants into the fracturing fluid, so it is necessary to study the influence of different factors on the spontaneous imbibition replacement efficiency of nanosurfactants. In this study, the basic properties of nanosurfactants such as particle size, oil-water interfacial tension (IFT), and the wetting modification effect were tested, and the influence of surfactant type, concentration, temperature, and pressure on imbibition replacement efficiency was studied. The main conclusions are as follows: (1) The particle size of the nanosurfactant that was synthesized by a microemulsion method is 12-21 nm, which indicated good injectability in tight cores. Moreover, the IFT values between the crude oil and five kinds of 0.30 wt % nanosurfactants were all lower than 0.15 mN/m, and nanosurfactant C had the best wetting modification effect with increasing the contact angle by 100.30°. (2) The type and concentration of surfactant have a certain influence on imbibition replacement efficiency, and appropriate concentration of anionic nanosurfactant is beneficial to enhancing the imbibition replacement efficiency. The imbibition replacement efficiency of 0.30 wt % anionic surfactant C solution is higher than that of nonionic and cationic surfactant solutions, and the imbibition replacement efficiency is as high as 33.386% under NTP. (3) The nanosurfactant in brine is prone to forming fine emulsified oil droplets with crude oil and activates the oil droplets in the small pores to enhance the imbibition replacement efficiency. The crude oil type, temperature, and pressure can influence imbibition replacement efficiency, and the influence of crude oil type and temperature is greater than that of pressure. This work further studies the influencing factors of imbibition replacement efficiency.
