In drilling fractured low-permeability reservoirs, bridging temporary plugging agent particles, because of their large sizes, are difficult to achieve tight plugging, and these particles exhibit low self-degradability. To address these technical challenges, a self-degradable bridging temporary plugging agent SMNP-1 was prepared via inverse microemulsion polymerization and using liquid microfluidics technology. The plugging agent SMNP-1 was synthesized using acrylamide (AM) and sodium p-styrenesulfonate (SSS) as the monomers, and β-cyclodextrin diacrylate ester (β-CD-AA) as the crosslinking agent. The molecular structure of SMNP-1 was verified with infrared spectrometer, and the particle size distribution and micromorphology of SMNP-1 were characterized with laser particle size analyzer and scanning electron microscope (SEM). Laboratory experiments were conducted to investigate SMNP-1 for its water absorption and swelling performance, adsorption performance, temporary plugging and unplugging performance, self-degradability, pressure-bearing capacity, and compatibility. Experimental results demonstrate that at elevated temperatures, SMNP-1 exhibits a moderate volumetric expansion rate after absorbing water, and a strong adsorption capacity. The SMNP-1 particles, after high-temperature treatment, show a normal size distribution and are morphologically nano-micron sized microspheres. At test temperatures of 100 ℃, 120 ℃, 140 ℃ and 160 ℃, the rates of SMNP-1 to plug natural cores are 96.88%, 96.63%, 96.57% and 95.27%, respectively. After 240 h of high temperature exposure, the unplugging rates of SMNP-1 are 87.22%, 89.95%, 93.27% and 96.13%, respectively, and the rates of self-degradation are 52.05%, 56.40%, 63.04% and 74.11%, respectively, demonstrating remarkable reservoir protection effect. At test temperature of 100 ℃, the maximum displacement pressure difference is 55 MPa, and a maximum displacement pressure difference of 25 MPa can still be achieved when the temperature is increased to 160 ℃, demonstrating an excellent plugging performance. SMNP-1 exhibits little effect on the rheology of drilling fluids, it can effectively enhance the wall-building capacity of a drilling fluid after fluid-loss and the reservoir protection effect. SMNP-1 has been successfully applied in the wild-cat well Xinsheng-1.
Shale oil drilling is faced with challenges such as high friction, poor stability of drilling fluid additives in high-temperature high-salinity environment and increasingly stringent environment protection requirement. To address these problems, a novel ester-based lubricant LUBM-1 was developed through one-pot synthesis with raw materials such as ricinoleic acid, oleic acid, n-octanol and iso-octanol. Laboratory experiments were conducted to systematically evaluate LUBM-1 for its molecular structure characteristics and its performance in water-based drilling fluids. FT-IR characterization shows that the synthetic product has high degree of esterification and stable molecular structure. Laboratory drilling fluid experimental results show that a treatment of 1% LUBM-1 can remarkably reduce the friction coefficient of the base drilling fluid to 0.069 and the wear scar diameter, demonstrating an excellent friction reducing and wear resistant ability. The membrane formed by LUBM-1 remains stable in high-temperature and high-salinity environment; after aging at 200 ℃, it still reduces the friction of the drilling fluid by at least 80%, and in a drilling fluid containing 30% NaCl, LUBM-1 still retains high lubrication performance, showing excellent performance in high-temperature high-salinity environment. Water-based drilling fluids treated with LUBM-1 show good rheology, very low filtration rate, strong inhibitive capacity and low bio-toxicity which is required by "green-drilling". The results of the research show that LUBM-1 can significantly enhance the lubricity and borehole wall stabilizing performance of water-based drilling fluids, providing a reliable technical solution for complex shale oil drilling with high safety, high performance and environmental friendliness.
Lost circulation and wellbore instability have been encountered in drilling the Permian fractured formations in the sag west to the well Pen-1 in the Junggar Basin. To understand how oil-based/water-based drilling fluids affect the propagation pressure of a fracture, a comparative analysis was conducted on the effects of oil-based/water-based drilling fluids on the propagation pressure of the fracture. Physical simulation experiments on the propagation of core fractures were conducted through rock mechanical test, analysis of rock physical parameters as well as drilling fluid property test, and the law of the integrated action of the rock properties and drilling fluid properties on the propagation of fractures was systematically investigated. The conclusions of the experiments are as follows: ① fracturing the fractured cores with oil-based and water-based drilling fluids to observe the magnitude of the propagation pressure of the fractures, and it was found that the propagation pressure of the fractures measured in tests with oil-based drilling fluids is remarkably higher than that measured in tests with water-based drilling fluids. ② It was revealed that the drilling fluid viscosity is the primary factor controlling the propagation pressure of a fracture, and its importance exceeds the filtration property of the drilling fluid. High drilling fluid viscosity hinders the effective propagation of the pressure inside the fracture, hence significantly increasing the propagation pressure. ③ It was clarified that rock permeability is the prerequisite for the drilling fluid filtrates to form a “pressure drop zone” at the tip of a fracture and hence to promote the propagation. For oil-based drilling fluids, although having strong wetting capacity, their high viscosity and extremely low filtration rate work together to suppress the formation of the “pressure drop zone”, thereby masking the wettability potential. ④ Based on the experimental results, the contribution of each factor to fracture propagation pressure is quantified, the importance of these factors is listed as this: drilling fluid viscosity > rock permeability > filtration property > brittleness index > wettability > porosity. This research reveals the core mechanisms of oil-based and water-based drilling fluids in affecting the propagation pressure of a fracture, clarifies the key control factors and their relative importance, and provides an important theoretical support to the scientific selection of drilling fluid types and the formulation of control strategy for wellbore stability in safely drilling fractured formations.
Conventional core flow experiment cannot be used to accurately measure the salt crystallization characteristics of high-density solids-free saltwater completion fluids in downhole working conditions.To address this problem,an evaluation method integrating gas flooding of core and dynamic visualization analysis was proposed.Using nitrogen flooding to simulate the actual flowback environment,and microscopic visualization technology to in-situ observe salt-out behavior,the influences of temperature(80-120℃),sudden pressure change(3.5 MPa-atmospheric pressure)and gas flowback on salt crystallization were investigated,and an optimized experimental method was established to analyze the crystallization characteristics of potassium formate completion fluid in reservoir environment.The experimental results show that temperature and sudden change of pressure are the main causes of salt-out damage from potassium formate completion fluid,among which the flash evaporation effect induced by gas flowback is the dominant trigger;at 120℃,the amount of salt precipitated can reach 8-9 g/L.When a single factor of temperature and pressure changes,the percent core permeability recovery is about 65%.Under the simultaneous action of temperature drop and pressure reduction,core damage was aggravated,the percent core permeability recovery drops to 62.33%.The main mechanisms of salt-out in porous media are the bridging growth of crystals at the narrow pore throats and their deposition on the walls of pores.After optimizing the experimental method,salt-out can be suppressed by maintaining constant temperature and constant pressure(120℃,1 MPa),and the percent recovery of permeability can be increased to 75.3%,10-21%higher than that under unsteady conditions.The optimized research method provides a theoretical and methodological guidance for accurately evaluating downhole salt-out damage characteristics and optimizing completion fluids.
An oilfield in the Middle East has a major sandstone reservoir that is composed of mainly sandstone and argillaceous siltstone, the cement of which is mainly feldspar. The reservoir rocks are unconsolidated and the pores therein are easy to be blocked by sand production. Conventional acid job takes effect slowly and may result in dispersion of the loose sandstone, thereby exacerbating sand production. In this paper the mechanism of pore blocking by sand production is analyzed, and a technology of blocking removal through compound acidizing for unconsolidated sandstone reservoirs is presented. Using a clue of “first stabilizing the borehole wall, and then removing the blocking”, this technology is able to mitigate formation damage by pore blocking and to maintain the stability of the reservoir formation. Through laboratory experiment a sandstone stabilizer was developed for high flushing rates. At a flow rate of 1,800 mL/h, the rate of sand production can be steadily controlled below 0.01%. Through the synergism among different working fluids, taking “removing more scale and dissolving less sandstone” as a goal, an acid fluid for blocking removal through differential erosion was developed. Using this acid fluid, the rate of scale dissolution is ≥95% and the rate of sand dissolution is <25%. The rate of sandstone dissolution can be brought under control with this acid, thereby maintaining the stability of the rock structure. Field test results show that this technology can improve the average production rate and effective production life of oil wells, and it provides a theoretic basis and practical guidance for stimulating unconsolidated sandstone reservoirs through blocking removal with acidizing treatment.
