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Production performance of Permian Basin wells and potential for improving oil recovery
Uzun, Ilker Ozan
Uzun, Ilker Ozan
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2023
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2025-06-24
Abstract
The Permian Basin is one of the most prolific oil and gas-producing geologic basins in the United States. The Permian Basin is located in West Texas and Southeastern New Mexico. It has supplied more than 33.4 billion barrels of oil and 118 Tcf of natural gas during a 100-year period (EIA 2022). The ever-increasing water production and usage (e.g., hydraulic fracture stimulation) in the Permian Basin requires produced water management by the operators.
Oil recovery from shale reservoirs is a very slow process because of the extremely low permeability of oil-containing pores, with the ultimate oil recovery of around 3 to 8%. Classical waterflooding or gas flooding in unconventional reservoirs is not plausible because of the small pore size and low permeability of the shale matrices. Therefore, creative approaches are needed to increase oil production without relying on large quantities of water injection to enhance oil production, which became the motivation for my research with the objective to integrate geology, fluid flow theory, experimental data, and reservoir modeling to assess production performance and enhance hydrocarbon recovery in the Permian basin.
Injecting rich gas or CO2 in such formations in a cyclic fashion (the huff-n-puff process) increases oil recovery substantially but is expensive because of gas compression and injection equipment. Another alternative is to use solvent-containing water in a cyclic fashion (e.g., solutions of ketones and ethoxylated alcohols). Using brine-containing 3-pentanone or surfactant-based solutions results in much additional oil recoveries by cleaning the micro- and macro-fracture flow paths in the stimulated reservoir volume.
In this study, the efficacy of injecting a brine solution containing a very small amount of 3-pentanone or a non-ionic surfactant (0.5 to 1.5 percent) determined to enhance oil recovery (EOR). The aqueous EOR huff-n-puff method is more cost-effective and easier to apply than the gas injection huff-n-puff process for the Wolfcamp formation in the Permian Basin.
As an initial review of Wolfcamp formation, the production data for wells drilled into the Wolfcamp Formation of the Delaware Basin between 2012 and 2021 was reviewed and organized. A set of bubble maps to identify and visualize cumulative oil, gas, and water production changes was created. The maps showed the maturity of the basin where gas-prone wells are the majority in the northern and northwestern parts, and the southern area is more oil-prone. The wells drilled in Lea, Loving, and East-Reeves counties show the most oil production in one year of production. The gas production is highest in Culberson, North Reeves, and Loving counties. Furthermore, water production is significant throughout the region regardless of the produced hydrocarbon type.
Wettability measurements (i.e., contact angles and wettability indices) and the associated water-rock capillary pressures reflect the interactions between the reservoir rock and the pore fluids, which, in turn, strongly affects the distribution of fluids in the reservoir pores. Consequently, I conducted contact angle experiments on five different unconventional reservoir formations across the US and measured interfacial tension (IFT) between oil and brine from the associated formations. Furthermore, I conducted contact angle experiments on the Wolfcamp formation rock samples using ketone and surfactant solutions.
For engineering analysis, first, a static geologic model utilizing well-logs and core data was built on Petrel. Subsequently, the aforementioned static model was used to construct a compositional dual-porosity reservoir model using the CMG-GEM commercial reservoir modeling software in conjunction with the experiments. Second, Rate Transient Analysis (RTA) to determine the stimulated permeabilities associated with the hydraulic fracture stimulation was conducted. Next, Wolfcamp PVT report were evaluated and used to build a reservoir fluid model with CMG’s Winprop module. Finally, the compositional reservoir model was history match the field production data to validate the model.
After the numerical model was ascertained by history matching, three distinct enhanced oil recovery (EOR) techniques, the huff-n-puff gas injection, ketone solution injection, and surfactant solution injection were implemented for the selected well. Afterward, a sensitivity analysis was conducted to determine the characteristics that had the most significant influence on the reservoir performance of the well in the three enhanced oil recovery (EOR) scenarios. A broad conclusion is that the use of ketone solutions resulted in a significant increase in oil production, while injection rate magnitude and period, soaking period, and solvent concentration affected the magnitude of the incremental oil recovery outcome.
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