The Past, Present, and Future of Chemical Enhanced Oil Recovery Methods in Yates Field Unit
- Raul Valdez (Kinder Morgan Inc.) | Pamela A. Boring (Kinder Morgan Inc.) | Edward J. Lewis (Kinder Morgan Inc.) | Seth Haymes (Kinder Morgan Inc.) | Gonzalo A. Hernandez (Kinder Morgan Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Improved Oil Recovery Conference, 31 August - 4 September, Tulsa, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2020. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 5 Reservoir Desciption & Dynamics, 4.1 Processing Systems and Design, 3 Production and Well Operations, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 5.8.7 Carbonate Reservoir, 2 Well completion, 4.1.2 Separation and Treating, 3 Production and Well Operations, 2.4 Hydraulic Fracturing, 5.4.1 Waterflooding, 1.6 Drilling Operations, 5.3.6 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4 Facilities Design, Construction and Operation, 5.4 Improved and Enhanced Recovery, 5.5.2 Core Analysis, 5.4 Improved and Enhanced Recovery, 5.8 Unconventional and Complex Reservoirs, 5.2 Reservoir Fluid Dynamics
- Yates, Fractured, Carbonate, Polymer, Surfactant
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Chemical Enhanced Oil Recovery (EOR) methods have been implemented in a West Texas fractured carbonate. Due to the partially oil-wet nature of Yates field and slightly viscous oil (5-7 cP), surfactant injection was implemented to alter wettability and polymer was injected in the waterflood area to improve displacement efficiency, respectively. Single well huff-n-puff (HnP) surfactant treatments (late 1980's-today) and well-to-well pilots (1990's-2000's) have increased incremental oil production relative to base decline. Optimum surfactant chemicals were chosen based on laboratory results, reservoir performance, and economic viability. Polymer injection was carried out over a 6 year span (1983-1989) in which 55+ million pounds of polymer was injected; however the interpretation and analysis was complicated due to concurrent drilling, workover activities, and no prior waterflood development.
Design parameters key to the surfactant implementation included: surfactant type and concentration, Critical Micelle Concentration (CMC), fluid saturations, oil composition, formation water salinity, fracture intensity, and treatment soak timing. Laboratory experiments included interfacial tension, contact angle, adsorption, fluid phase stability, Amott tests, and coreflooding. Numerical models were developed to help understand the sensitivity of each parameter on EOR performance and guide the design of treatments.
Field implementation of surfactant included different surfactant types: anionic, non-ionic, and cationic. HnP treatments were followed by a soak period before returning the well to production and conducting flow back water analysis. Overall, HnP treatments using cationic surfactant resulted in the highest efficiency in terms of barrels of oil per kilogram of surfactant. Well-to-well tests were only conducted with non-ionic surfactants and showed mixed results.
Design parameters for polymer injection such as fluid viscosity, concentration, adsorption and molecular weight were determined through coreflooding and fluid viscosity experiments. Two polymer types, high and low molecular weight, were studied and manufactured in-field and used in 200 or more injectors either continuously or alternating with produced water. Polymer injection was not effective in improving displacement efficiency in the water flood area of Yates reservoir and was suspended in 1989.
The scale of field implementation and analysis of the impact of chemical injection on oil production in a massive, densely fractured carbonate field has provided valuable insight and learnings for future development and will be discussed. Other chemical EOR methods currently under investigation such as foam and other wettability altering technologies will also be discussed.
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