Waterflood in a viscous oil reservoir is not very efficient because the water fingers through the oil due to adverse viscosity. Typically, thermal methods are used to recover viscous (and heavy) oil. However, thermal methods can be inefficient when the depth of the reservoir is high and pay thickness is low. Nonthermal chemical enhanced-oil-recovery (EOR) methods are being developed as alternatives. Recently, a new low-cost chemical EOR technology called alkali−cosolvent−polymer (ACP) flooding has been developed which does not use any synthetic surfactant. In viscous oil reservoirs, the oil recovery in the first 30 years is more important than the ultimate recovery, which may take many hundreds of years. The purpose of this study is to identify the optimum ACP slug viscosity and the optimum timing for the initiation of the ACP process. ACP formulations that achieve ultralow tension were developed. Since the sweep efficiency is challenging in viscous oil reservoirs, ACP floods were performed in a quarter 5-spot lab model. Experimental results were numerically simulated and matched using an in-house simulator UTCHEM. The results of the experiments indicate that the tertiary ACP flood with the oil to ACP slug viscosity ratio between 2 and 4 could recover more than 80% of the oil with a reasonable pressure gradient. This unfavorable mobility of the chemical slug is beneficial considering both oil recovery and pressure drop. The timing of the start of the tertiary flood did not change the cumulative oil recovery very much. However, a shorter waterflood resulted in an earlier oil recovery.
A mechanism of alkaline flooding to improve recovery for viscous oils was found to be related to the transition of emulsions from low viscosity and low water-oil-ratios (WORs) to high viscosity and high WORs. Distinct behaviors of emulsions formed by alkaline brines and acidic, viscous oils were experimentally observed by mixing alkaline brines and oils at different WOR. Depending on the oil type and the brine formulation, different transition behaviors of the emulsions were observed. In some cases, low viscosity oil-in-water (O/W) emulsions were observed at low WOR while high viscosity water-in-oil (W/O) emulsions were observed at high WOR. This transition of emulsion type and properties was associated with significant uplift in recovery by alkaline flooding over water flooding as observed in sandpack floods. Meanwhile, when the emulsions did not exhibit transitional behaviors and remained the same type with varying WOR, the incremental recovery by alkaline flooding was very small, regardless of whether the viscosities of the emulsions were high or low. A novel mechanism associated with flow re-direction and sweep efficiency improvement was proposed and validated using micromodel experiments. Results of this work lead to new opportunities and screening criteria to apply alkaline flooding for viscous, acidic oils.
Milne Point Field initiated the first polymer injection pilots on the North Slope of Alaska starting in 2018 and have rapidly progressed to full-field polymer injection within four years. The two initial pilot projects injected at an initial total rate of 6,000 bwpd utilizing 5 horizontal injection wells. Expansion activities began two years later in 2020 with the addition of 4 additional polymer injection units. By the end of 2021, total field polymer injection rate was 32,000 bwpd via 29 horizontal injection wells. Targeted reservoirs have average permeabilities ranging from 100 – 1000md and in-situ oil viscosities ranging from 40 cp to 1300 cp. Both secondary and tertiary floods are being conducted in both greenfield and brownfield development areas each with varying, yet all promising, results. The highest observed recovery is in a secondary polymer flood pattern at 27% of OOIP with an oil viscosity of 850 cp and no water breakthrough observed to date. Responses in injection well injectivities have ranged from as low as 0% up to 50% loss to date and are observed to be correlated by well spacing and total reservoir mobility. Multiple polymer injection designs exist throughout the field which were driven by existing infrastructure, specific needs from pattern to pattern, and increased learning over time. A logistics system has also been successfully developed that allows for large scale polymer flood on the North Slope of Alaska. The intent of this paper is to a.) provide sufficient historical context to give insight into field development when polymer flood was started b.) highlight what has been done to date in regards to moving from polymer flood concept to near full field expansion and c.) present observed results with the hope that they can help set expectations for future polymer flood projects.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.