Formulating a novel drilling mud using bio-polymers, nanoparticles, and SDS and investigating its rheological behavior, interfacial tension, and formation damage.

Formation damage is a well-known problem that occurs during the exploration and production phases of the upstream sector of the oil and gas industry. This study aimed to develop a new drilling mud formulation by utilizing eco-friendly bio-polymers, specifically Carboxymethyl Cellulose (CMC), along with nanostructured materials and a common surfactant, sodium dodecyl sulfate (SDS). The rheological properties of the drilling fluid and the impact of additives on its properties were investigated at the micromodel scale, using a flow rate of 20 mL/h. The polymer concentration and nano clay concentration were set at two levels: 0.5 wt% and 1 wt%, respectively, while the surfactant content was varied at three levels: 0.1 wt%, 0.4 wt%, and 0.8 wt%. The results of the interfacial tension (IFT) analysis demonstrated a significant decrease in the interfacial tension between oil and water with the increasing concentration of SDS. Furthermore, following the API standard, the rheological behavior of the drilling fluid, including the gel strength and thixotropic properties of the mud, was evaluated with respect to temperature changes, as this is crucial for ensuring the inherent rheological stability of the mud. The rheological analysis indicated that the viscosity of the mud formulation with nanoparticles experienced a reduction of up to 10 times with increasing shear rate, while other formulations exhibited a decline of 100 times. Notably, the rheological properties of the Agar specimen improved at 150 °F due to its complete solubility in water, whereas other formulations exhibited a greater drop in viscosity at this temperature. As the temperature increased, drilling fluid containing nanostructured materials exhibited higher viscosity.

Development of a Computational Fluid Dynamics Compositional Wellbore Simulator for Modeling of Asphaltene Deposition.

The asphaltene problem is a two-step process: (1) asphaltene precipitation, as predicted by the thermodynamic model, and (2) asphaltene deposition, the amount of which is estimated by the kinetic model. Asphaltene precipitation is a prerequisite but not a sufficient condition for deposition. Deposition is dependent on other factors such as surface properties, phase behavior, rheology, and flow patterns. As a result, in addition to understanding thermodynamic and kinetic models, it is critical to also understand flow models. In fact, multiphase flow modeling is at the core of simulation, and it must be coupled with thermodynamic and kinetic models. Numerous studies on modeling asphaltene deposition on pipe walls have been performed theoretically and experimentally, but a comprehensive theory to properly understand this phenomenon has not yet been presented. In thermodynamic modeling, the perturbed chain statistical associating fluid theory (PC-SAFT) equation of state is used to predict the asphaltene phase behavior. In this study, we show that the proposed PC-SAFT model is more accurate than the solid model used in commercial software. Unlike prior research that neglected flow patterns or used empirical relations to model multiphase flow, this study simulates multiphase flow using separate momentum equations for each phase. Among the existing kinetic models, the Kurup model has been used to predict the asphaltene deposition profile in the wellbore due to its greater compatibility for computational fluid dynamics application. The results of the proposed model show good agreement with field case data of asphaltene deposition thicknesses along the wellbore tubing.