ABSTRACT
One of the most challenging issues when drilling under high-temperature, high-pressure (HT/HP) conditions is wellbore instability caused by clay swelling and fluid loss of the drilling mud. One of the most difficult issues when drilling under high-temperature, high-pressure (HT/HP) conditions is wellbore instability caused by clay swelling and fluid loss in drilling mud. Two modified PVOHs, nonionic and cationic polymers made from sodium bentonite clay and deionized water at concentrations of 0.08, 0.28, and 0.49 wt.%, were introduced to WBM percent. A series of specific gravity and mud rheology experiments at 25, 55, and 85 °C indicated that both values drop monotonically with increasing temperature, regardless of PVOH addition or concentration. A temperature increase of 30 °C decreases the mud viscosity of WBM (without PVOH) by 18% from its starting value, on average. Only 0.1% of cationic and nonionic polymer reduces viscosity by 10% and 0%, respectively. Experimenting with mud samples for 5 h revealed that adding nonionic polymers enhances mud filtration by up to 34.7%, 1.25 times more than that achieved from cationic polymers under the same filtration circumstances. Increasing the filtration temperature moderately affects mud cake generation due to increased mud swelling index and preferential adsorption by nonionic polymer. The latter observation was corroborated by determining the polymer content of the filtrates. Therefore, it was shown that nonionic polymers adsorbed more (118.9 mg/g) than cationic polymers (84.51 mg/g). Increased filtration temperature moderately affects mud cake generation due to increased mud swelling index and preferential adsorption by nonionic polymer. The latter observation was corroborated by testing the filtrates for the polymer content. As a result, it was discovered that nonionic polymer adsorbed more (118.9 mg/g) than cationic polymer (84.51 mg/g). Thermogravimetry analysis (TGA) finally tested the thermal stability of polymers.
ABSTRACT
The present work investigates the contribution of asphaltene aggregation to bitumen viscosity subject to ultrasound irradiation. A West-African bitumen with a viscosity of 12043cP at room temperature was sonicated at low (38 kHz) and mild frequency (200 kHz) under controlled gas environment including air, nitrogen (N2) and carbon dioxide (CO2). The rheology of the bitumen, asphaltene content analyses as well as spectral studies were conducted. Herein was found that sonicating the bitumen at 200 kHz under air-environment reduces the initial viscosity up to 2079cP, which was twice larger than that obtained when a low frequency was used. In respect of the gas environment, it was shown that ultrasound irradiation under N2 environment could lower the bitumen viscosity up to 3274cP. A positive correlation between the asphaltene content and the viscosity reduction was established. The results from the spectral analyses including Fast Fourier Infrared and the observations from Scanned Electron Microscope were consistent with the rheological studies and led to the argument that the viscosity reduction results from either the scission of long chain molecules attached to the aromatic rings (when the applied frequency was altered under fixed gas environment) or the self-aggregation of asphaltene monomers (when gas environment was changed at fixed frequency).
ABSTRACT
In this study, we introduce a new method for the prediction of the viscosity of bitumen diluted with light oil under reservoir temperature and pressure. This two-step method works as follows: first, predicting the bitumen viscosity under reservoir temperature and pressure using the classical Mehrotra and Svrcek model, and then subsequently using it in the modified Van Der Wijk (MVDM) model. This model formed from the modification of the original Van Der Wijk model was developed from the consideration of the interactions between like molecules in different binary components of the mixture. In this study, the bitumen viscosity was predicted with an average absolute deviation percentage (AAD%) of 3.86. The accuracy of the MVDM was investigated from the experimental results obtained from the rheological studies of three binary mixtures of light oil (API 32°) and bitumen (API 7.39°). Dead oils were mixed on a mass fraction basis. The viscosity was measured at a temperature range of 45-110 °C and a pressure range of 0.1-6 MPa. For comparison purposes, a reworked Van Der Wijk model (RVDM) was used in the same method and compared to the MVDM. The latter was more accurate than the RVDM with AAD% values of 8.88, 8.02, and 5.07 in predicting the viscosity of the three mixtures of 25, 32.5, and 50% bitumen with light oil. On the other hand, the RVDM had AAD% values of 12.42, 11.43, and 7.87 for the same mixtures, respectively. The applicability of this method was further verified by comparing its accuracy to another reported method using published data and it was found that the MVDM had AAD% values of 1.86, 6.55, and 2.823 when predicting the viscosities of the three mixtures under reservoir temperature and pressure conditions.
ABSTRACT
Injecting nanofluids (NFs) has been proven to be a potential method to enhance oil recovery. Stranded oil is produced by wettability alteration where nanoparticles form a wedge film on pore wall surfaces, which is thought to shrink the pore space of the reservoir. Furthermore, ensuring the stability of the injected NF during the application is a major challenge. A low permeability reservoir and salinity of water make the response of NF injection to the formation damage more difficult. This article, therefore, studied the formation damage induced by the injection of alumina nanofluids (Al-NFs) in a relatively low permeability (7.1 mD) sandstone core. The salinity of the postflush water was also considered to mitigate the destructive impact. Al-NF was formulated by dispersing alumina nanoparticles (Al-NPs) in an aqueous solution of sodium dodecylbenzene sulfonate (SDBS) at its critical micelle concentration (CMC, 0.1 wt %). The formation damage, inherent to Al-NF injection, was evaluated by core-flooding tests. The assays consisted of the injection of 1 PV Al-NF (0.05 wt %) at the trail of which postflush at different salinities was flooded. The study found that the salinity of the postflush has an effect on the formation damage and oil recovery factor (RF). A chase water with a salinity concentration of 3 wt % sodium chloride (NaCl) produced an RF of 8.7% compared to a base case of water-flooding with a pressure drop of up to 13 MPa across the core (70 mm in length). These results pertained to the deposition of Al-NPs at the injection end. However, lowering the postflush salinity to 1 wt % NaCl mitigated the formation damage as evidenced by the decrease in pressure (35%) and an increase in RF to 17.2%.
