Viscoelastic surfactant (VES)-based fracturing fluids can reduce the risk of formation damage when compared with conventional polymer-based fracturing systems. However, many VES systems lose viscoelasticity rapidly under high-temperature conditions, leading to high fluid leakoff and problems in proppant placement. A gemini cationic VES-based system offering thermal stability above 250°F and its efficiency in friction reduction is presented in this paper. Rheology measurements were conducted on viscoelastic cationic gemini surfactant fluids as a function of temperature (70 – 300°F) and surfactant concentration. The length of surfactant alkyl chain was varied to investigate the impact of surfactant chain length on VES fluid viscosity at elevated temperatures. The effect of flow rate on friction reduction capability of the surfactant fluid was measured on a friction flow loop. Foam rheology measurements were conducted to evaluate the VES fluid's ability to maintain high temperature viscosity with reduced surfactant concentration. A gemini cationic surfactant was used to prepare a viscoelastic surfactant system that could maintain viscosity over 50 cP at a shear rate of 100 s−1up to at least 250°F. With this system, viscoelastic gel viscosity was maintained without degradation for over 18 hours at 250°F, and the fluid showed rapid shear recovery throughout. Decreasing the average alkyl chain length on the surfactant reduced the maximum working temperature of the resulting viscoelastic gel and showed the critical influence of surfactant structure on the resulting fluid performance. The presence of elongated, worm-like micelles in the fluid provided polymer-like friction reduction even at low surfactant concentrations, with friction reduction of over 70% observed during pumping (relative to fresh water) up to a critical Reynolds number. Energized fluids could also be formulated with the gemini surfactant to give foam fluids suitable for hydraulic fracturing or wellbore cleanouts. The resulting viscoelastic surfactant foams had viscosities over 50 cP up to at least 300°F with both nitrogen and carbon dioxide as the gas phase. The information presented in this paper is important for various field applications where thermal stability of the treatment fluid is essential. This will hopefully expand the use of VES-based systems as an alternative to conventional polymer systems in oilfield applications where a less damaging viscosified fluid system is required.
Administrators are currently being challenged to maintain high quality patient care in the face of shrinking health care resources. The introduction of different skill mix ratios has been suggested as one way to help manage health care costs. This paper briefly reviews the literature and research data on skill mix, discussing the relevant issues and identifying the positive and negative implications of this approach. It concludes with suggestions for further research.
Surfactants are used in gas well deliquification to generate foam to lift liquid condensates and brine from a well during gas production. In this paper, the effect of various hydrocarbon components typically found in natural condensates on selected foaming surfactants was studied. The screening methodology used a modified blender test to evaluate foam height and its half-life. The foaming results from the blender tests are reported for a number of alpha olefin sulfonates (AOS), alkyl ether sulfates (AES), and betaines at 25°C and ambient pressure. The surfactants were also evaluated using dynamic foam carry-over apparatus at ambient conditions for further validation. This work helps to elucidate problems associated with choosing the proper gas well deliquification surfactant suitable for a condensate of a specific composition.
In mixed- to oil-wet reservoirs characterized by intense natural fracturing where the dominant displacement mechanism is gravity drainage, surfactant injection can lead to a shift in wettability and incremental oil production. In some cases, oil can also re-imbibe back into the rock matrix after the oil saturation has been reduced upon initial exposure to surfactant, suggesting limited permanence in the wettability shift. The re-imbibition phenomenon is investigated in this paper utilizing Amott cells. Three cationic surfactants (C12-, C12-16-, C16-based) solutions with interfacial tensions (IFT) between 0.18 to 0.95 mN/m were pre-selected to be evaluated. Current applications of the C12- based surfactant in the Yates field is considered successful based on incremental oil recovery seen during the treatment. Silurian dolomite rock samples were flooded with Yates crude oil before being aged at 140 °F for 6 weeks. For the imbibition tests, synthetic brine was set as the external phase within the Amott cell and the recovery of oil was recorded periodically. After the imbibition tests ended, the rock samples were placed in an inverse Amott cell with the Yates oil as the external phase. Baseline tests were first conducted to show that without a surfactant in the oil or brine, no imbibition occurred. With a surfactant concentration of 3,000 ppm, oil recovery at the end of the imbibition tests varied from 34% to 64% of the original oil volume in the core sample. During the re-imbibition test, a large amount of oil was able to re-imbibe into the rock, displacing the brine. Most of the displacement occurred within the first two weeks. The net oil recovery, taken as the final volume of oil recovered in the imbibition test minus the final volume of oil re-imbibed into the rock, ranged from 0% to 18%. Given the possibility of surfactant dilution in field applications, another set of tests were conducted with 1,500 ppm. A reduction in oil recovery during imbibition was observed for both the C12- based surfactant and the C12-16- mixture. Partition coefficients were determined for each of the tested surfactants and the ion pair mechanism was used to explain the net oil recovery results. Lastly, the impact of rock permeability on re-imbibition was investigated. Results show increasing permeability may lead to a linear response in oil re-imbibition,therefore minimizing the permeability range when selecting rock samples may be necessary when conducting the re-imbibition test. The importance of oil re-imbibition is demonstrated in the experimental study and we make an argument for conducting both the imbibition and re-imbibition tests to better evaluate surfactant efficacy. The improved understanding of wettability alteration should lead to advancements in chemical enhanced oil recovery designs for field treatments.
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