Transforming Challenges into Opportunities: First High Salinity Polymer Injection Deployment in a Sour Sandstone Heavy Oil Reservoir

Abstract

This paper describes the design and implementation of a one-spot enhanced oil recovery (EOR) pilot using high-salinity water (∼166,000 ppm TDS) in a sour, sandstone, heavy-oil reservoir (∼5 mol% hydrogen sulfide) based on an extensive laboratory study involving different polymers and operating conditions. In view of the results of this one-spot EOR pilot, a multi-well, high-salinity polymer-injection pilot is expected to start in 2020 targeting the Umm Niqqa Lower Fars (UNLF) reservoir in Kuwait. Polymer flooding is normally carried out using low- to moderate-salinity water to maintain favorable polymer solution viscosities in pursuit of maximum oil recovery. Nevertheless, low- to moderate-salinity water sources such as seawater tend to be associated with a variety of logistical, operational, and commercial challenges. For this study, laboratory experiments were conducted in conjunction with reservoir simulation to confirm the technical viability of polymer flooding using high-salinity water. Thereafter, a one-spot EOR pilot was executed in the field using a well near the location of the planned multi-well pilot to confirm the performance of the selected polymer vis-à-vis injectivity and oil desaturation. The one-spot EOR pilot described in this paper was successfully executed by performing two Single-Well Chemical Tracer (SWCT) tests. For the first stage of the pilot, 200 bbl of produced water (up to 166,000 ppm TDS) were injected into the test well in an attempt to displace mobile oil out of the investigated pore space. Following this produced water injection, an SWCT test (Test #1) was carried out and measured the remaining oil saturation to be 0.41 ± 0.03. This saturation measurement represents the fraction of oil remaining in the pore space of a cylindrical portion of the Lower Fars reservoir, measured from the wellbore out to a radius of 3.02 feet, after produced water injection. After the completion of Test #1 and subsequent recovery of the injected produced water, the same zone was treated with a 200-bbl injection of polymer solution. Following this 200-bbl polymer injection, a second SWCT test (Test #2) was performed and measured the remaining oil saturation to be 0.19 ± 0.03 out to a radius of 3.38 feet. These results indicate that polymer injection may offer considerable improvement to oil recovery over conventional waterflooding alone. Performing polymer flooding in a sour, heavy-oil reservoir using high-salinity water is a challenging and unprecedented undertaking worldwide. In addition to the improved incremental oil recovery demonstrated by this pilot, enabling the use high-salinity produced water for polymer flooding is expected to result in significant benefits for cost-efficiency and operational ease by reducing or eliminating problems commonly associated with the sourcing, treatment, and handling of less saline water in the field.