No abstract

While synthetic polymer floods are being deployed in mild temperature and low salinity fields, many oilfields (harsh conditions) remain inaccessible due to performance limitations, and concentration requirements, which adversely affect project economics. Historically, biopolymers have been considered in such reservoirs, with mixed results. Xanthan was used in the 1980's, while more recently schizophyllan polymer was tested in a pilot study. This study presents scleroglucan polymers as a class of viscosifiers that demonstrate excellent performance in harsh temperature and salinity reservoirs. Scleroglucan polymers do not suffer from catastrophic drop in viscosity in the presence of high concentration of divalent ions. This makes produced water re-injection projects without water treatment a reality. This work demonstrates that cost-effective, high purity EOR grade Scleroglucan polymers, show excellent performance in lab trials as related to excellent rheological properties, injectivity, bio and thermal stability and with minimal shear degradation. Injectivity tests demonstrated good propagation through cores without blockage or injectivity issues. Resistance factors and residual resistance factors are in the desirable range. Core floods carried out in sandstone and carbonate outcrop cores demonstrated that adsorption values and oil recoveries are consistently in the expected range for polymer recoveries. Shear degradation studies showed that recycling scleroglucan through a centrifugal pump causes less than 5% drop in viscosity after 100 passes while synthetic polymer showed substantial loss after a single pass and a 50% drop after 10 passes through the same pump. Capillary shear testing (API RP 63 method) of scleroglucan shows little change in viscosity upon multiple passes through shear regimes greater than 150,000 s−1. Scleroglucan polymer solution showed less than 25% drop in viscosity after exposure to 115 °C for six months. No change in viscosity was observed at 95 °C after one year. Scleroglucan has no compatibility issues through 6 months (at 37, 85, and 95 °C) with glutaraldehyde and tributyl tetradecyl phosphonium chloride (TTPC) biocides. Long term biostability studies at various temperatures and salinities are ongoing - current data will be presented. Scleroglucan has excellent stability in the presence of hydrogen sulfide (H2S) and ferrous species (Fe2+) under fully aerobic conditions! This work provides insight on the potential of using EOR grade scleroglucan for CEOR in harsh condition reservoirs. Currently, the program is moving towards pilot implementation of a scleroglucan formulation to demonstrate large scale hydration, long term injectivity and oil recovery.

Millimeter-sized (10-mm to mm) preformed particle gel (PPG) has been used to control water flow through superhigh-permeability zones and fracture zones in mature oil fields. When the PPG is extruded into target zones, the gel can form a cake on the surface of low-permeability, unswept formations. This cake reduces the effectiveness of conformance control and the amount of oil that can be recovered from unswept oil formations. Thus, this study evaluated the effectiveness of using hydrochloric acid (HCl) to remove gel cakes induced during conformance-control treatments.The interactions between HCl and PPG were evaluated to understand the swelling, deswelling, and gel strength after adding acid. A Hassler core holder was then used to determine the core permeability after gel and acid treatments. Gels swollen in brine concentrations of 0.05, 1, and 10% were injected into a sandstone core having a variety of permeabilities. Brine was then injected in cycles through the gel into the core. The core permeability was measured after the gel-particle injection and after the core surface of the gel cake was soaked in the acid solution for 12 hours. The results indicate that particles swollen in brine concentrations of 0.05% caused more damage than those swollen in higher concentrations of brine. The damage increased as the core permeability increased for all the swollen gels. HCl removed the gel cake effectively; varying the HCl concentration did not cause a significant difference in the gel-cake removal efficiency. The gel was found to swell much less in HCl solutions than in brine. After the gel was deswollen in acid, the gel strengths were found to be higher than when the gel was swollen in brine. This work concludes that HCl can be used effectively to mitigate the damage induced by PPGs.

No abstract

Oil recovery from naturally fractured carbonate reservoirs has always been a challenging task because of two inherent features, (1) Fracture networks which aggravate the effectiveness of water or chemical flooding and (2) Oil-wet matrix which limits the capillary imbibition process that governs the recovery in the fractured reservoirs. To overcome these challenges, we propose a technique that combines two existing enhance oil recovery (EOR) methods. Millimeter-sized preformed particle gels (PPGs) treatment along with surfactant imbibition. This coupled method can improve the imbibition process by providing fast transport mechanism for the surfactant to the oil-wet matrix which will accelerates the recovery rate. The coupled injection of PPGs and surfactant will result in a higher injection pressure gradient in the reservoir because of the high flow resistance resulting from the gel particles. Which will generate an additional force to divert surfactant into the matrix area thus forced imbibition can be realized. The combination of PPG treatment and surfactant imbibition can be a viable EOR process that will provide more cost-effective method for improving oil recovery while reducing water production in naturally fractured reservoirs if the PPG and surfactant were chosen appropriately.