Previous rheological studies of water-base and oil-base muds have concentrated on fluid viscosities at elevated temperatures and pressures. This paper extends the data available to cold temperature regimes which can be expected to occur in the riser for deepwater wells. The rheology of eighteen different drilling fluids covering WBM, OBM and SBM have been evaluated between -1° to 90°C and 1 to 344.7 bar. The Herschel-Bulkley and Casson models both fitted the OBM and SBM rheograms very well. For the different WBM systems, the Herschel-Bulkley model also fitted the salt/polymer fluids and unweighted bentonite-based fluid rheologies, however, the Casson model best described the weighted bentonite-based fluid rheologies. The effect of the cold fluid viscosity in the riser on ECD for deepwater wells was assessed using a software model which uses a transient temperature simulator in conjunction with a hydraulic model which accounts for different mud viscosity throughout the wellbore. Comparing the ECD predictions with those calculated where the mud rheology is independent of temperature and pressure, the ECD was found to be underestimated by up to 6.1% for a SBM and overestimated by 3.1% for a WBM. If there are formations with small differences in the fracture and pore pressure gradients, then these variations in ECD could cause well control problems.

Understanding the behavior of the borehole temperature recovery process, which influences drilling operations, requires an adequate estimation of fluid temperature. The presence of salt in a saline formation changes the composition of the annular fluid and has a significant impact on the fluid temperature distribution during drilling operations. As a result, while drilling a saline formation, it is vital to examine the key parameter that determines an accurate estimate of fluid temperature. Using python software and statistical quantitative methods, this study proposes a simplified user-friendly computational system that analyzes the drilling fluid systems performance evaluation and selection optimization.The fluid temperature distribution of X Field in China was analyzed using Shan mathematical model as a base model. When compared to MWD data from the field, the model predicted the temperature distribution of the field with less than 10% error. An adjustment factor was introduced to the base model to accommodate for changes in annular fluid composition while drilling a saline formation. The findings show that salt concentration has an impact on fluid temperature distribution during drilling. The fluid temperature at the wellbore condition changes by at least 7% with both high and low adjustment factors. Because the salt in the formation inflow dissolves in the drilling fluid near the annulus, the rheology of the fluid combination changes.

This study investigates the role of clay mineral, polyacrylamide additive, and nanosilica solution in the creation of a cross-linked gel for well cement repair. Several experimental setups were developed using a rotational viscometer and an Anton rheometer to investigate the impact of nanosilica particles on the rheology and performance prediction of the sealing gel. The results of varying the nanosilica concentration revealed that silica solution with a concentration of 15−25 wt % produced a lower gel strength property over a suitable gelation period, whereas silica solution with a concentration of 30−40 wt % displayed a higher gel strength property but with a short gelation time. The findings also demonstrated that adding 0.15 wt % polyacrylamide (PAM) to 18 wt % nanosilica significantly enhanced the properties of the gel, increasing about 135% in the gel strength, 429% in the yield point, and 122% in the storage modulus without posing any operational issues. The gelation of the nanosilica solution in the downhole environment, on the other hand, was shown to be greatly improved by the clay mineral bentonite, which was present in the formation rock. This research's findings have improved the oil and gas industry's understanding of the materials that might be used to improve a sealing gel's rheological properties for well integrity operations.

No abstract

The leakage of hydrocarbon fluids through cracks in the annular cement and CO2 storage is a major concern to the Petroleum Industry. A significant risk is posed when repairing leakage in a micro annuli channel with smaller apertures. A low-viscosity sealant that can generate a long-lasting resilient seal is desired. The solution to sealing these channels might lie in a novel application using nano-silica Gel. In this study, laboratory tests were carried out to examine the capabilities of nano-silica gels to seal the cracks. Analyzing its rheological property, the gel strengths of nano-silica gels were found to increase with an increase in nano-silica concentration. Additionally, it was discovered that as the concentration of nano-silica increases, the sealing and leakage pressures, defined as the pressures before and after water breakthrough, respectively, increase as well. With a typical 15% concentration of nano silica in gel, a sealing pressure gradient of 80.2 psi/in and a leakage pressure gradient of 30 psi/in at a leaking rate of 1 cc/min were noted. To validate the validity of the experimental results, a mathematical model was developed to predict the leakage rate of sealed fractures. The model suggests that the young’s modulus of sealant is a key property of nano-sealants and further investigations are needed to validate the mathematical model for quantitative use. This study suggests a novel strategy for enhancing cement zonal isolation and reducing cement failure in oil and gas sector.