Electrical submersible pump (ESP) operation is compromised by free gas, resulting in premature pump failure and production losses in new wells. It is essential to detect the onset of abnormal operations. We develop a model that predicts abnormal ESP operation when the free gas level increases in the pump. The model compares operation parameters with the parameters of normal operating ranges; it shuts down the ESP when necessary. We used a Schlumberger PIPESIM software (version 2017.01) to perform nodal analysis technique; we tested the model using the other multiphase correlation model and field case studies (where the gas problem in ESP was reported). We employ a homogenous model to calculate the differential pump pressures at various gas volume fractions. Nodal analysis of the intake and discharge point predicted the commencement of abnormal ESP conditions and the associated parameters (critical gas fraction, minimum operating pump intake pressure, and pump discharge pressure). The model results were similar to other surging correlation models (e.g., Romero, Dunbar, Turpin, Cirilo, and Zhou models); they were also identical to field case studies. We identify three performance stability phases when an ESP is exposed to free gas. These are the normal and abnormal operating ranges, as well as the ESP shutdown condition. Modeling permits careful monitoring of ESP operations that can be compromised by free gas.

This study reports the size-dependent interactions of silica nanoparticle (NP) dispersions with oil, which facilitate oil recovery from sandstone rock. Herein, we studied various 7–22 nm sized colloidal silica NPs (CSNPs; the colloidal state when dispersed in aqueous solutions) and fumed silica nanoparticles (FSNPs; the dry powder state). Interfacial tension at the oil-nanofluids interface declined with decreasing NP size in a range from 7 to 22 nm. This is because NP spatial density at the interface increased with smaller particle size, thereby, the interface area per NP decreased to approximately 1/30, and interfacial energy had reduced enough. In addition, smaller NPs more strongly were adsorbed to the rock because of improved diffusion in suspension and increased adsorption density. This caused creating a wedge film between oil and rock, which changed the oil contact angle. Due to this effect, core flooding experiments indicated that oil recovery increased with decreasing particle size. However, FSNP dispersions exhibited low recovery factor because of particle aggregation. This phenomenon may facilitate massive permeability reduction, thus causing oil trapping inside rock pore. We found that both the sizes and types of CSNPs and FSNP affected the Interfacial tension at oil-water interface and rock surface wettability, which influenced ultimate oil recovery.

The depressurization method is known as the most productive and effective method for successful methane recovery from hydrate deposits. However, this method can cause considerable subsidence because of the increased effective stress. Maintenance of geomechanical stability is necessary for sustainable production of gas from gas hydrate deposits. In this study, the cyclic depressurization method, which uses changing the bottomhole pressure and production time during primary and secondary depressurization stage, was utilized in order to increase stability in the Ulleung Basin of the Korea East Sea. Various case studies were conducted with alternating bottomhole pressure and production time of the primary and secondary depressurization stages over 400 days. Geomechanical stability was significantly enhanced, while cumulative gas production was relatively less reduced or nearly maintained. Specially, the cumulative gas production of the 6 MPa case was more than three times higher than that of the 9 MPa case, while vertical displacement was similar between them. Therefore, it was found that the cyclic depressurization method should be applied for the sake of geomechanical stability.

The intake plugging of an electrical submersible pump (ESP) has presented a formidable challenge to conventional ESP wells. Attention to cumulative solid deposition is essential since it intensifies the intake plugging severity and impedes ESP performance. We present a new approach to evaluate the ESP performance degradation during increased intake plugging severity. In particular, we employ the intake plugging factor, rate-derating factor, and affinity law to calculate the new ESP speed at different plugging conditions. We used Schlumberger PIPESIM software to perform nodal analysis of the newly calculated ESP speed. The result was validated using the actual field data and compared to the field cases that reported the intake plugging issue. The nodal analysis showed a steady maximum ESP head with zero rate derating at the shut-in point. The intake plugging factor caused a significant reduction in the ESP operating rate and increased pump intake pressure and annulus liquid level. Based on the existing intake plugging field data, we established the quantitative standard for the normal and abnormal intake plugging factor range. The observed results agreed with the field downhole data recorded during the intake plugging problem. We identified that regulating the ESP speed to the reduced operating rate could minimize unexpected pump stoppage. It is also possible to carefully monitor the intake plugging problem by combining the annulus liquid level, the signature of pump intake pressure, and a deadhead test.

We investigated oil recovery from porous rock using nanoscale colloidal dispersions, formed by adsorption of an anionic polymer [poly-(4styrenesulfonic acid-co-maleic acid); PSS-co-MA] and a zwitterionic surfactant [N-tetradecyl-N, N-dimethyl-3-ammonio-1-propanesulfonate, TPS] onto silica nanoparticles. In an emulsion, colloidal dispersion enhanced the stability of the oil-water interface in the absence of particle aggregation; the hydrophobic alkyl chains of TPS shifted into the oil drop, not only physiochemically, stabilizing the oil-water interface, but also promoting repulsive particle-to-particle interaction. Core flooding experiments on residual oil saturation as a function of capillary number, at various injection rates and oil viscosities, showed that the residual oil level was reduced by almost half when the zwitterionic surfactant was present in the colloidal dispersion. Consequently, the result revealed that this colloidal dispersion at the interface provides a mechanically robust layer at the oil-water interface without particle aggregation. Thus, the dispersion readily entered the pore throat and adhered to the oil-water interface, lowering the interfacial tension and improving oil recovery.