A simple huff ‘n’ puff (HnP) injection and flowback utilizing a nonionic surfactant solution to drive enhanced oil recovery (EOR) in a depleted Eagle Ford "black oil" unconventional well has been executed and analyzed. The pilot injection was performed in December 2020, with pressures below the estimated fracture gradient. 12,300 bbl of surfactant solution were injected into the 6,000 ft lateral. In January 2021, the well was put back on production with oil and water flowrate data being gathered and samples collected. Within three months of the well being put back onto production after surfactant stimulation, the well produced at oil rates over five times what it had produced prior to stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the pre-stimulation rates. Utilizing a long-term hyperbolic fit to historical data as the "most likely" production scenario in the absence of a stimulation as a "baseline", incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing WTI prices at time of production and the known costs of the pilot result in project payout time less than one year and project IRR in excess of 80% with only incremental production to-date. These results prove the potential for techno-economic viability of HnP EOR techniques using surfactants for wettability alteration in depleted unconventional oil wells.
The well was chosen from a portfolio of unconventional Eagle Ford black oil window wells that were completed in the 2012-2014 timeframe. The goal of the test was to demonstrate successful application of lab work to the field, and to demonstrate economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on lab work completed on oil, brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical & economic objectives of the field test were to: 1) inject surfactant solution to contact sufficient matrix surface area that measurable and economically attractive amounts of oil could be mobilized, 2) measure the amount of surfactant produced in the flowback stream to determine the amount of surfactant retained in the reservoir and 3) prove the concept of using wettability alteration, in conjunction with residual well energy, in a depleted well can result in economically attractive incremental recovery.
Surfactant selection was completed in the lab using oil and brine gathered from potential target wells, and rock from nearby wells completed in the same strata. Several surfactant formulations were tested and a final nonionic formulation was chosen on the basis of favorable wettability alteration and improved spontaneous imbibition recovery. The design for the pilot relied on rules of thumb derived from unconventional completion parameters. Rates, pressures, and injectant composition were carefully controlled for the single day, "bullhead" injection. Soak time between injection and post-stimulation restart of production was inferred from lab-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates have been monitored since production restart. Flowback samples were analyzed for TDS (total dissolved solids), ions, and surfactant concentration.
