Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection. In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
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.
There has been increasing interest in different greenhouse gas (GHG) management strategies including the reduction of methane emissions and carbon sequestration. It has been proposed that reinjection of excess produced natural gas can mitigate GHG emissions without compromising oil production. Foam has been used as a method to reduce gas mobility, delay gas breakthrough, and improve sweep efficiency. However, industrial production of petroleum-based chemicals or surfactants to generate foam can be dependent on fossil-based resources that can be scarce or expensive. The main objective of this work was to reduce chemical cost and oil-based chemical dependency by developing an alternative biosurfactant formulation to generate high quality foam. Biosurfactant blends were ranked in comparison to single component anionic and nonionic surfactants and other commercially available surfactant blends. Bulk stability "shake tests" were done to look at initial foamability and stability of the different candidates and then corefloods in sandpacks and surrogate rocks were completed to look at if formulations would generate foam in porous media with methane gas and in the presence of crude oil. Experiments showed success in replicating chemical performance by replacing traditional oil-based surfactants with bio-based lignin derived surfactants even at reservoir conditions. High-quality biosurfactant foams reduced chemical costs, provided an alternative method to dispose of large amounts of hydrocarbon gas, and improved oil recovery through foam displacement.
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