Mechanistic Understanding of Delayed Oil Breakthrough in Near-Critical Point Shale Oil Reservoirs
Authors: Jia Bao , Wang Yongchao , He Qin , Lliu Tianyang , Xian Chenggang , Jia Wenfeng , Jiang Ming , Temizel Cenk 
Published: October 2022

Abstract
Recently, significant breakthroughs have been made in exploring one specific shale oil field, northeast China. On-site observation reveals that the appearance of oil at the wellhead is only seen a long time after fracturing in many wells. The extended period of purely water production complicates subsurface flow behavior and hinders the increase of medium- and long-term oil production. Strong coupling between phase behavior and relative permeability curves in the reservoir with the near-critical point initial condition restricts the efficient development of this kind of shale oil. The work gives detailed descriptions of the geology and petrophysics background of the target formation. A series of compositional simulation models are constructed to reveal the cause of the late oil breakthrough. The delayed oil breakthrough is highly related to the coexistence of three phases that are not seen in common reservoirs. Such reservoirs’ early-time production behavior is positively associated with the gas-liquid relative permeability curves and initial water saturation. Oil-water relative permeability curves affect the water-cut behavior depending on wetting properties. The potential oil-wet property slows down oil breakthroughs. Conceivably, purely gas and water phases exist due to the nanopore confinement of crude oil phase behavior; thus, the late oil production is barely related to the gas-liquid relative permeability curves.
The Q formation is widely developed in Songliao Basin, where the oil and gas generation indexes are promising. Few tectonic movements and large-scale fault zones occurred in this area suitable for oil and gas exploration and development.1,2 The first member of the Q formation contains high-quality source rocks and high hydrocarbon generation potential. The shale formation strata are similar to the Forth Worth basin and Barnett shale stratigraphic assemblage in the United States, containing miscellaneous mineralogies. The shale of the Q formation is felsic; generally, the first member has less clay than the second and third members.3
During the development of G Sag in the first member, deferred oil production appears in many horizontal wells after fracturing. The effluent at the wellhead continues to be pure water phase for a long time. This phenomenon did not occur in China's Longdong shale oil, Mahu tight oil, Jimusar shale oil, and Changqing tight oilfields.4–6 For example, the average oil appearance time in the demonstration area of three-dimensional development of the Mahu tight conglomerate reservoir is just 1.67 days, and the initial production increased rapidly. Similarly, according to our literature survey, such postponed oil production has not been recorded in shale reservoirs in the United States. The late and long-term water production occurrence means that complex phase transition and multiphase flow behavior have occurred in the subsurface, regulating medium- and long-term oil and gas production. The late appearance of oil is closely related to the initial state of the reservoir at the critical point of the phase envelope and the three-phase flow of oil, gas, and water. Generally speaking, the initial pressure of the reservoir is much higher than the saturation pressure, so the oil and water phases coexist, and the oil phase is in a single-phase state.7,8 For many light crude oils in G sag, the initial state of the reservoir is close to the critical temperature and critical pressure point, implying that oil, gas, and water might coexist initially, leading to the unique production flow circumstance after fracturing. The objectives of this study are: 1. provide a relatively comprehensive background petrophysical delineation of the Q formation; 2. establish exploratory reservoir simulation models based on PVT data to interpret the delayed oil production; the inceptive models are compositional with deep insight into the coupled phase behavior and relative permeability curves; 3. investigate possible nanopore confinement on the relative permeability interpretation.