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Collaborating Authors
Results
Polymer Stabilized Foam Rheology and Stability for Unconventional EOR Application
Griffith, Christopher (Chevron) | Jin, Julia (Chevron) | Linnemeyer, Harry (Chevron) | Pinnawala, Gayani (Chevron) | Aminzadeh, Behdad (Chevron) | Lau, Samuel (Chevron) | Kim, Do Hoon (Chevron) | Alexis, Dennis (Chevron) | Malik, Taimur (Chevron) | Dwarakanath, Varadarajan (Chevron)
Abstract It has been shownthat injecting surfactants into unconventional hydraulically fractured wells can improve oil recovery. It is hypothesized that oil recovery can be further improved by more efficiently distributing surfactants into the reservoir using foam. The challenge is that in high temperature applications (e.g., 240 F) many of these formulations may not make stable foams as they have only moderate foaming properties (short half-life). Therefore, we are evaluating polymers that can be used to improve foam stability in high temperature wells which has the potential to improve oil recovery beyond surfactant only injection.Surfactant stabilized nitrogen foams were evaluated using a foam rheometer at pressures and temperatures representative of a field pilot well. The evaluation process consisted of measuring baseline properties (foam viscosity and stability) of a surfactant stabilized foam without any added stabilizer. Next, conventional enhanced oil recovery polymers (HPAMs, modified-HPAMs, and nonionic polymers) were added at different concentrations to determine their impacts on foam stability. Our results demonstrate that inclusion of a relatively low concentration (0.05 wt% – 0.2 wt%) of polymer has a pronounced impact on foam stability. It was determined that reservoir temperature plays a key role in selecting astabilizing polymer. For example, at higher temperatures (>240 F), sulfonated HPAM polymers at just 0.2 wt% more than doubled the stability of the foam. The polymer that was selected from this lab work was tested in a foam field trial in an unconventional well. It is thought that improved foam stability could potentially help improve the distribution of surfactants in fracture network and further improve oil recovery.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms
Aminzadeh, Behdad (Chevron CTC) | Chandrasekhar, Sriram (Chevron CTC) | Srivastava, Mayank (Chevron CTC) | Tang, Tom (Chevron CTC) | Inouye, Art (Chevron CTC) | Villegas, Mauricio (Chevron GOM) | Valjak, Monika (Chevron GOM) | Dwarakanath, Varadarajan (Chevron CTC)
Abstract Water floods are typically conducted using the least expensive, easily available, non-damaging brine. Very little attention is given to the possibility of changing brine composition to improve oil recovery. Over the last 20 years, there has been laboratory and field trial evidence that shows changing brine chemistry, especially to low salinity, can sometimes increase the recovery. The various mechanisms of additional oil recovery from changing brine chemistry are not entirely clear. We report here on the effect of using low salinity and divalent altered brines on oil recovery through a variety of laboratory methods and materials. More than twenty corefloods were conducted to evaluate the effect of brine chemistry and initial wettability on incremental oil recovery. We also performed phase behavior tests, contact angle measurements, and wettability index measurements to evaluate recovery mechanisms. Initial wettability of the core was altered by ageing it with different crude oil containing wide range of asphaltene content. The core flood with lowest wettability index (least water-wet) produced about 12% incremental recovery while the most water-wet core only produced ∼ 4% during the secondary low salinity waterflood.
- Asia (0.93)
- North America > United States > Texas (0.47)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Berea Sandstone Formation (0.98)
- North America > United States > Pennsylvania > Appalachian Basin > Berea Sandstone Formation (0.98)
- (2 more...)
Improving Recovery of a Viscous Oil Using Optimized Emulsion Viscosity
Aminzadeh, Behdad (Chevron Energy Technology Company) | Hoang, Viet (Chevron Energy Technology Company) | Inouye, Art (Chevron Energy Technology Company) | Izgec, Omer (Chevron Energy Technology Company) | Walker, Dustin (Chevron Energy Technology Company) | Chung, Doo (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Tang, Tom (Chevron Energy Technology Company) | Lolley, Chris (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- North America > Canada > Alberta (0.28)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)