Natural Gas Liquids-Injection Pilot Reveals Fluid-Level Mechanisms in Bakken

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 4485635, “Integrated Field/Laboratory Evaluation of a Natural Gas Liquids-Injection EOR Pilot in the Bakken Formation,” by Nidhal Badrouchi and Lu Jin, University of North Dakota, and Arvo Buck, Chord Energy, et al. The paper has not been peer-reviewed. _ This work presents a detailed laboratory-based evaluation integrated with field-pilot test results of a cyclic natural gas liquids-injection project in the Middle Bakken. This work presents a detailed laboratory-based evaluation integrated with field-pilot-test results of a cyclic natural-gas-liquids (NGL) injection in the Middle Bakken. The study focuses on experimentally quantifying how injected NGL modifies produced-oil density, molecular weight, phase behavior, and compositional structure, and how these laboratory observations correlate with field production and pressure trends. NGL Pilot Design Enhanced Oil Recovery (EOR) Site Description and Well Selection. The pilot test was conducted in the Teal drilling-spacing unit (DSU) at the Alger Field in North Dakota. The field produces from two primary pay zones, the Middle Bakken and the Three Forks units. True vertical depth to the pay zone ranges from 9,600 to 11,000 ft, placing the reservoir within the pressure and temperature regime required for NGL to develop full miscibility with Bakken crude. The field contains 386 active oil wells, with individual wells completed across 11–60 hydraulic fracturing stages and horizontal lateral lengths ranging from 120 to 13,000 ft—a wide range that reflects the evolution of completion practices across the field’s multiyear development history. The production performance of the field reflects both the prolific initial productivity of the Middle Bakken and Three Forks reservoirs and the rapid decline characteristic of tight unconventional systems. The estimated ultimate oil recovery for the field is 154,041,585 bbl, with current cumulative production representing approximately 68% of the estimated total recoverable resource under primary depletion. This underscores both the maturity of the field and the magnitude of the remaining unrecovered resource that EOR could potentially access. The Teal well is situated within a single-well DSU measuring 1 mile by 1 mile. This isolation is paramount in pilot selection; it eliminates the risk of frac hits or interference from neighboring producers. The well features a horizontal lateral of approximately 5,000 ft, stimulated through 23 fracture stages and 84 clusters. This completion provides enough fracture surface area to facilitate the mass transfer required for EOR without the extreme complexity of high-density completions. Before its conversion to an EOR well in September 2025, the Teal well had a productive life of nearly 9 years. Its cumulative production totals indicate a mature well that has effectively drained its immediate stimulated reservoir volume (SRV). By August 2025, the bottomhole pressure (BHP) had declined to approximately 1,100 psi. This significant drawdown below the original reservoir pressure (greater than 8,000 psi) created the necessary voidage for NGL to be injected at high rates without immediately exceeding the formation’s fracture pressure.