Surfactant Enhanced Oil Recovery Improves Oil Recovery in a Depleted Eagle Ford Unconventional Well: A Case Study
Authors: Ataceri I. Z. , Saputra I. W. R. , Bagareddy A. R. , Elkady M. H. , Schechter D. S. , Haddix G. W. , Brock V. A. , Raney K. H. , Strickland C. W. , Morris G. R. 
Published: June 2023

Summary
A simple huff “n” puff (HnP) injection and flowback using 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. More than 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 flow rate data being gathered and samples collected. Within 3 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 before stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the prestimulation rates. Using a long-term hyperbolic fit to historical data as the “most likely” production scenario in the absence of stimulation as a “baseline,” incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing West Texas Intermediate (i.e., WTI) prices at the time of production and the known costs of the pilot result in project payout time less than 1 year and project internal rate of return in excess of 80%, with only incremental production to date. These results prove the potential for technoeconomic 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 time frame. The goal of the test was to demonstrate successful application of laboratory work to the field and economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on laboratory work completed on oil and brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical and 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 to achieve economically attractive incremental recovery.
Surfactant selection was completed in the laboratory 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 laboratory-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates were monitored since production restart. Flowback samples were analyzed for total dissolved solids (TDS), ions, and surfactant concentration.